Legacy Reserves 10-Q 7 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 06, 2015
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, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		69,458,155

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash	$ 3,661	$ 725
Accounts receivable, net:
Oil and natural gas	41,235	49,390
Joint interest owners	12,424	16,235
Other	254	237
Fair value of derivatives (Notes 6 and 7)	63,951	120,305
Prepaid expenses and other current assets	5,708	5,362
Total current assets	127,233	192,254
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	2,976,550	2,946,820
Unproved properties	48,322	47,613
Accumulated depletion, depreciation, amortization and impairment	(1,626,689)	(1,354,459)
Oil and natural gas properties using the successful efforts method, at cost	1,398,183	1,639,974
Other property and equipment, net of accumulated depreciation and amortization of $8,126 and $7,446, respectively	3,269	3,767
Operating rights, net of amortization of $4,731 and $4,509, respectively	2,286	2,508
Fair value of derivatives (Notes 6 and 7)	18,605	32,794
Other assets, net of amortization of $13,996 and $12,551, respectively	24,179	24,255
Investments in equity method investees	624	3,054
Total assets	1,574,379	1,898,606
Current liabilities:
Accounts payable	1,416	2,787
Accrued oil and natural gas liabilities (Note 1)	54,667	78,615
Fair value of derivatives (Notes 6 and 7)	985	2,080
Asset retirement obligation (Note 8)	3,028	3,028
Other (Notes 2 and 10)	9,757	11,066
Total current liabilities	69,853	97,576
Long-term debt (Note 2)	966,111	938,876
Asset retirement obligation (Note 8)	241,611	223,497
Other long-term liabilities	1,294	1,452
Total liabilities	$ 1,278,869	$ 1,261,401
Commitments and contingencies (Note 5)
Partners' equity (Note 9):
Limited partners' equity - 57,405,398 and 57,280,049 units issued and outstanding at June 30, 2014 and December 31, 2013	$ 35,261	$ 376,885
General partner's equity (approximately 0.03%)	(18)	53
Total partners' equity	295,510	637,205
Total liabilities and partners' equity	1,574,379	1,898,606
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2015 and December 31, 2014
Partners' equity (Note 9):
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2015 and December 31, 2014	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2015 and December 31, 2014
Partners' equity (Note 9):
Preferred equity	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2015 and December 31, 2014
Partners' equity (Note 9):
Preferred equity	$ 174,261	$ 174,261

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Other property and equipment, accumulated depreciation and amortization	$ 8,126	$ 7,446
Operating rights, amortization	4,731	4,509
Other assets, amortization	$ 13,996	$ 12,551
Limited partners' equity, units issued (in shares)	68,944,825	68,910,784
Limited partners' equity, units outstanding (in shares)	68,944,825	68,910,784
General partner's equity, percent	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 - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil sales	$ 59,113	$ 108,731	$ 109,409	$ 210,786
Natural gas liquids (NGL) sales	5,729	5,103	9,921	9,069
Natural gas sales	22,959	23,280	50,010	43,163
Total revenues	87,801	137,114	169,340	263,018
Expenses:
Oil and natural gas production	45,220	45,809	94,440	88,343
Production and other taxes	3,986	8,595	8,204	16,550
General and administrative	10,390	14,809	19,259	22,456
Depletion, depreciation, amortization and accretion	36,197	38,537	77,265	72,234
Impairment of long-lived assets	0	2,387	209,402	3,798
Gain (loss) on disposal of assets	(934)	(3,853)	1,007	(1,552)
Total expenses	94,859	106,284	409,577	201,829
Operating income (loss)	(7,058)	30,830	(240,237)	61,189
Other income (expense):
Interest income	176	216	382	439
Interest expense (Notes 2, 6 and 7)	(17,760)	(16,225)	(35,552)	(30,164)
Equity in income of equity method investees	24	191	103	183
Net gains (losses) on commodity derivatives (Notes 6 and 7)	(13,497)	(31,433)	6,983	(47,319)
Other	97	211	702	304
Loss before income taxes	(38,018)	(16,210)	(267,619)	(15,368)
Income tax (expense) benefit	(456)	(278)	291	(592)
Net loss	(38,474)	(16,488)	(267,328)	(15,960)
Distributions to Preferred unitholders	(4,750)	(2,194)	(9,500)	(2,194)
Net loss attributable to unitholders	$ (43,224)	$ (18,682)	$ (276,828)	$ (18,154)
Loss per unit - basic and diluted (Note 9) (in dollars per share)	$ (0.63)	$ (0.33)	$ (4.02)	$ (0.32)
Weighted average number of units used in computing net loss per unit -
Basic (in shares)	68,897	57,372	68,909	57,341
Diluted (in shares)	68,897	57,372	68,909	57,341

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Partners' Equity - 6 months ended Jun. 30, 2015 - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Equity	Preferred EquityLimited Partner	Preferred EquitySeries A Preferred Equity	Preferred EquitySeries B Preferred Equity	Incentive Distribution Equity	Unitholders' Equity	Unitholders' EquityLimited Partner	Unitholders' EquityGeneral Partner
Unitholders equity, beginning balance (in shares) at Dec. 31, 2014				2,300	7,200	100		68,911
Unitholders equity, beginning balance at Dec. 31, 2014	$ 637,205			$ 55,192	$ 174,261	$ 30,814		$ 376,885	$ 53
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued to Legacy Board of Directors for services (in shares)								66
Units issued to Legacy Board of Directors for services	604							$ 604
Unit-based compensation	2,554							$ 2,554
Vesting of restricted and phantom units (in shares)								73
Offering costs associated with the issuance of units	(71)							$ (71)
Units acquired in exchange for equity method investee interest (in shares)								(105)
Units acquired in exchange for equity method investee interest	(1,349)							$ (1,349)
Distributions to preferred unitholders & Distributions to common unitholders, $0.96 per unit		$ (9,500)	$ (9,500)				$ (66,605)	(66,605)
Net loss	(267,328)							$ (267,257)	(71)
Unitholders equity, ending balance (in shares) at Jun. 30, 2015				2,300	7,200	100		68,945
Unitholders equity, ending balance at Jun. 30, 2015	$ 295,510			$ 55,192	$ 174,261	$ 30,814		$ 35,261	$ (18)

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Partners' Equity (Parenthetical)	6 Months Ended
	Jun. 30, 2015$ / shares
Unitholders' Equity | Limited Partner
Distributions to unitholders (in dollars per share)	$ 0.96

Condensed Consolidated Stateme7

Condensed Consolidated Statement of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net loss	$ (267,328)	$ (15,960)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	77,265	72,234
Amortization of debt discount and issuance costs	2,680	2,111
Impairment of long-lived assets	209,402	3,798
(Gain) loss on derivatives	(8,078)	45,893
Equity in income of equity method investees	(103)	(183)
Distribution from equity method investee	191	1,129
Unit-based compensation	3,174	1,580
(Gain) loss on disposal of assets	1,007	(1,552)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	8,155	(18,893)
(Increase) decrease in accounts receivable, joint interest owners	3,811	(8,922)
Increase in accounts receivable, other	(17)	(95)
Increase in other assets	(241)	(1,676)
Increase (decrease) in accrued oil and natural gas liabilities	(1,368)	7,078
Increase (decrease) in accrued oil and natural gas liabilities	(23,948)	20,435
Decrease in other liabilities	(4,396)	(3,208)
Total adjustments	267,534	119,729
Net cash provided by operating activities	206	103,769
Cash flows from investing activities:
Investment in oil and natural gas properties	(23,704)	(503,220)
Increase in deposits on pending acquisitions	0	(5,800)
Proceeds from sale of assets	740	3,281
Investment in other equipment	(181)	(571)
Net cash settlements on commodity derivatives	77,526	(9,620)
Net cash provided by (used in) investing activities	54,381	(515,930)
Cash flows from financing activities:
Proceeds from long-term debt	155,000	1,011,000
Payments of long-term debt	(129,000)	(737,000)
Payments of debt issuance costs	(1,475)	(9,331)
Proceeds from the issuance of units, net	(71)	224,244
Distributions to unitholders	(76,105)	(69,197)
Net cash provided by (used in) financing activities	(51,651)	419,716
Net increase in cash and cash equivalents	2,936	7,555
Cash and cash equivalents, beginning of period	725	2,584
Cash and cash equivalents, end of period	3,661	10,139
Non-cash investing and financing activities:
Asset retirement obligations associated with properties sold	(4,553)	(3,641)
Asset retirement obligations associated with property acquisitions	18,756	48,230
Units acquired in exchange for equity method investee interest	1,349	0
Incentive distribution units issued in exchange for oil and natural gas properties	$ 0	$ 30,814

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
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, 2015 and for the three and six months ended June 30, 2015 and 2014 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, 2014 . 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), 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, 2015 and December 31, 2014 : June 30, December 31, (In thousands) Revenue payable $ 15,660 $ 19,267 Accrued lease operating expense 17,861 21,177 Accrued capital expenditures 3,870 20,773 Accrued ad valorem tax 10,709 9,382 Other 6,567 8,016 $ 54,667 $ 78,615 (c) Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 will become effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not expect the adoption of ASU 2015-03 will have a material impact 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. On July 9, 2015, the FASB approved a one-year delay of the standard's effective date. Therefore, 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.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following as of June 30, 2015 and December 31, 2014 : June 30, December 31, 2015 2014 (In thousands) Credit Facility due 2019 $ 135,000 $ 109,000 8% Senior Notes due 2020 300,000 300,000 6.625% Senior Notes due 2021 550,000 550,000 985,000 959,000 Unamortized discount on Senior Notes (18,889 ) (20,124 ) Total Long-Term Debt $ 966,111 $ 938,876 Credit Facility Previous Credit Agreement: On March 10, 2011, Legacy entered into a five -year $1 billion secured revolving credit facility (as amended, the "Previous Credit Agreement"). Borrowings under the Previous Credit Agreement were set to mature on March 10, 2016. Current Credit Agreement: 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 80% 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 was $700 million as of June 30, 2015. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year with the next redetermination scheduled for October 1, 2015. 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. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.50% to 2.50% , or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00% , plus an applicable margin from 0.50% to 1.50% per annum, determined by the percentage of the borrowing base then in effect that is drawn. The Current Credit Agreement contains various covenants that limit Legacy's ability to: (i) incur indebtedness, (ii) enter into certain leases, (iii) grant certain liens, (iv) enter into certain swaps, (v) make certain loans, acquisitions, capital expenditures and investments, (vi) make distributions other than from available cash, (vii) merge, consolidate or allow any material change in the character of its business and (viii) engage in certain asset dispositions, including a sale of all or substantially all of its assets. The Current Credit Agreement also contains covenants that, among other things, require Legacy to maintain specified ratios or conditions as follows: (i) secured debt as of the last day of the most recent quarter to EBITDA in total over the last four quarters of not more than 2.5 to 1.0, (ii) 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 2.5 to 1.0 and (iii) 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 FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives. As of June 30, 2015 , Legacy had approximately $135 million drawn under the Current Credit Agreement at a weighted-average interest rate of 1.69% , leaving approximately $564.9 million of availability under the Current Credit Agreement. For the six -month period ended June 30, 2015 , Legacy paid in cash $2.4 million of interest expense on the Current Credit Agreement. The borrowing base was redetermined subsequent to June 30, 2015 . Please see Note 12, Subsequent Events for further details. At June 30, 2015 , Legacy was in compliance with all covenants of 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 our 8% Senior Notes due 2020 (the "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. In addition, prior to December 1, 2015, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes at the redemption price of 108% with the net proceeds of a public or private equity offering. 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., 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. Interest is payable on June 1 and December 1 of each year. 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 our 6.625% Senior Notes due 2021 (the "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. Interest is payable on June 1 and December 1 of each year.

Acquisitions Acquisitions

Acquisitions Acquisitions	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions On June 4, 2014, Legacy purchased a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy Rocky Mountain, LLC , a subsidiary of WPX Energy, Inc., (the "WPX Acquisition") for a net purchase price of $360.0 million . Consideration included both cash and 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units"), 100,000 of which vested immediately and the remainder of which are available to vest and also subject to forfeiture pursuant to the terms of a related Incentive Distribution Unitholder Agreement. This acquisition was accounted for as a business combination. The fully vested Incentive Distribution Units have been reflected in the financial statements at their estimated issuance date fair value of $30.8 million . No value was ascribed to the unvested Incentive Distribution Units upon the closing of the WPX Acquisition as the vesting of the unvested Incentive Distribution Units is dependent upon the consummation of future transactions with WPX and such Incentive Distribution Units will be a portion of the consideration of any such future transactions. The allocation of the WPX Acquisition 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 $ 403,980 Future abandonment costs (43,989 ) Fair value of net assets acquired $ 359,991 Pro Forma Operating Results The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013. 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, 2014 2014 (In thousands) Revenues $ 153,518 $ 301,270 Net loss attributable to unitholders $ (21,722 ) $ (16,091 ) Loss per unit — basic and diluted $ (0.38 ) $ (0.28 ) Units used in computing income (loss) per unit: Basic and diluted 57,372 57,341

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Cary D. Brown, Chairman of the board of LRGPLLC, Kyle A. McGraw, Director and Executive Vice President and Chief Development Officer of LRGPLLC and Dale Brown, Director of LRGPLLC, own interests in partnerships which, in turn, own a combined non-controlling 4.16% interest as limited partners in a partnership which, until November 10, 2014, owned the building that Legacy occupies. Monthly rent is $66,120 , without respect to property taxes and insurance. The lease expires in September 2020.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
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, 2015 , we estimate the value of our total future obligation to be approximately $58.5 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, 2015
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, 2015 : Fair Value Measurements at June 30, 2015 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, 2015 (In thousands) LTIP liability (a) $ — $ (28 ) $ — $ (28 ) Oil and natural gas derivatives — 87,367 (4,811 ) 82,556 Interest rate swaps — (985 ) — (985 ) Total $ — $ 86,354 $ (4,811 ) $ 81,543 (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 LIBOR rates and interest rate swaps. 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, 2015 2014 2015 2014 (In thousands) Beginning balance $ (2,485 ) $ 14,552 $ 555 $ 20,615 Transfers(a) — (14,552 ) — (14,552 ) Total losses (3,275 ) — (6,632 ) (6,740 ) Settlements, net 949 — 1,266 677 Ending balance $ (4,811 ) $ — $ (4,811 ) $ — Losses included in earnings relating to derivatives still held as of June 30, 2015 and 2014 $ (3,492 ) $ — $ (4,811 ) $ — (a) As part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments, with the exception of Midland-Cushing crude oil differential swaps, previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) were transfered to Level 2 instruments during the period ended March 31, 2014. 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 our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition 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. Assets measured at fair value during the six -month period ended June 30, 2015 include: Fair Value Measurements During the Six Months Ended June 30, 2015 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) $ — $ — $ 198,095 Acquisitions (b) $ — $ — $ 1,923 (a) Legacy reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be 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. During the six -month period ended June 30, 2015 , Legacy incurred impairment charges of $209.4 million as oil and natural gas properties with a net cost basis of $407.5 million were written down to their fair value of $198.1 million . In order to determine fair value, 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. (b) Assets and liabilities acquired in a business combination are recorded at fair value. During the six -month period ended June 30, 2015 , Legacy acquired oil and natural gas properties, inclusive of unproved acreage acquisitions, with a fair value of $1.9 million in multiple individually immaterial transactions. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. 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. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties 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 $135 million as of June 30, 2015 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, 2015 , the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $260.7 million and $440.0 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, 2015
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, most 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, 2015 and 2014 : Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Beginning fair value of commodity derivatives $ 133,242 $ 5,397 $ 153,099 $ 17,673 Total gain (loss) - oil derivatives (12,649 ) (33,770 ) 945 (46,030 ) Total gain (loss) - natural gas derivatives (848 ) 2,337 6,038 (1,289 ) Crude oil derivative cash settlements paid (received) (27,364 ) 6,244 (59,564 ) 8,800 Natural gas derivative cash settlements paid (received) (9,825 ) (234 ) (17,962 ) 820 Ending fair value of commodity derivatives $ 82,556 $ (20,026 ) $ 82,556 $ (20,026 ) 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, 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 $ 136,664 $ (54,108 ) $ 82,556 Total derivative assets $ 136,664 $ (54,108 ) $ 82,556 Offsetting Derivative Liabilities: Commodity derivatives $ (54,108 ) $ 54,108 $ — Interest rate derivatives (985 ) — (985 ) Total derivative liabilities $ (55,093 ) $ 54,108 $ (985 ) December 31, 2014 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 $ 223,778 $ (70,679 ) $ 153,099 Total derivative assets $ 223,778 $ (70,679 ) $ 153,099 Offsetting Derivative Liabilities: Commodity derivatives $ (70,679 ) $ 70,679 $ — Interest rate derivatives (2,080 ) — (2,080 ) Total derivative liabilities $ (72,759 ) $ 70,679 $ (2,080 ) As of June 30, 2015 , 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 Time Period Volumes (Bbls) Price per Bbl Price Range per Bbl July-December 2015 282,522 $79.51 $52.00 - $99.85 2016 228,600 $87.94 $86.30 - $99.85 2017 182,500 $84.75 $84.75 As of June 30, 2015 , 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 Time Period Volumes (Bbls) Price per Bbl Price Range per Bbl July-December 2015 1,656,000 $(1.78) $(1.75) - $(1.90) 2016 2,928,000 $(1.60) $(1.50) - $(1.75) As of June 30, 2015 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long put, a short put and 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 2015 673,440 $64.78 $89.78 $110.57 2016 621,300 $63.37 $88.37 $106.40 2017 72,400 $60.00 $85.00 $104.20 As of June 30, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and 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 2016 183,000 $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, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and a fixed-price swap as indicated below: Average Short Put Average Swap Time Period Volumes (Bbls) Price per Bbl Price per Bbl July-December 2015 506,000 $77.73 $93.98 As of June 30, 2015 , Legacy had the following NYMEX Henry Hub, West Texas Waha, ANR-OK and CIG-Rockies 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 2015 11,706,400 $4.13 $3.11 - $5.82 2016 23,019,200 $3.43 $3.32 - $5.30 2017 21,600,000 $3.37 $3.32 - $3.39 2018 21,600,000 $3.37 $3.32 - $3.39 2019 19,800,000 $3.38 $3.38 - $3.39 As of June 30, 2015 , 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 2015 4,020,000 $3.66 $4.21 $5.01 2016 5,580,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of June 30, 2015 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, NGPL Midcon, California SoCal NGI, San Juan Basin and West Texas WAHA 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 2015 Average Volumes (MMBtu) Price per MMBtu NWPL 6,000,000 $(0.13) NGPL 240,000 $(0.15) SoCal 120,000 $0.19 San Juan 240,000 $(0.12) WAHA 3,000,000 $(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 market 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, 2015 2014 2015 2014 (In thousands) Beginning fair value of interest rate swaps $ (1,540 ) $ (4,047 ) $ (2,080 ) $ (4,759 ) Total loss on interest rate swaps (143 ) (109 ) (291 ) (283 ) Cash settlements paid 698 824 1,386 1,710 Ending fair value of interest rate swaps $ (985 ) $ (3,332 ) $ (985 ) $ (3,332 ) The table below summarizes the interest rate swap position as of June 30, 2015 : Estimated Fair Market Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2015 (Dollars in thousands) $ 29,000 3.070 % 10/16/2007 10/16/2015 $ (277 ) $ 13,000 3.112 % 11/16/2007 11/16/2015 (160 ) $ 12,000 3.131 % 11/28/2007 11/28/2015 (149 ) $ 50,000 2.500 % 10/10/2008 10/10/2015 (399 ) Total fair market value of interest rate derivatives $ (985 )

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2015
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, 2015 and year ended December 31, 2014 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 226,525 $ 175,786 Liabilities incurred with properties acquired 18,756 50,487 Liabilities incurred with properties drilled — 941 Liabilities settled during the period (1,271 ) (2,918 ) Liabilities associated with properties sold (4,572 ) (5,891 ) Current period accretion 5,201 8,120 Asset retirement obligation - end of period $ 244,639 $ 226,525

Partners' Equity

Partners' Equity	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Partners' Equity	Partners' Equity Preferred Units On April 17, 2014, Legacy issued 2,000,000 of its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "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 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "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 Series A Preferred Units and Series B Preferred Units (collectively, 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. Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of 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. 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. In addition, the vested and outstanding Incentive Distribution Units held by WPX 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 also has the ability to similarly convert any of its vested Incentive Distribution Units beginning three years after June 4, 2014. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX. 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, 2015 2014 2015 2014 (In thousands) Net loss $ (38,474 ) $ (16,488 ) $ (267,328 ) $ (15,960 ) Distributions to preferred unitholders (4,750 ) (2,194 ) (9,500 ) (2,194 ) Net loss available to unitholders (43,224 ) (18,682 ) (276,828 ) (18,154 ) Weighted average number of units outstanding 68,897 57,372 68,909 57,341 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 68,897 57,372 68,909 57,341 Basic and diluted loss per unit $ (0.63 ) $ (0.33 ) $ (4.02 ) $ (0.32 ) 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. For the three and six months ended June 30, 2014 , 264,097 restricted units and 323,965 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, 2015
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, 2015 , grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 2,180,140 units had been made, comprised of 266,014 unit option awards, 855,534 restricted unit awards, 862,064 phantom unit awards and 196,528 unit awards. The UAR 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. Due to Legacy’s historical practice of settling options and UARs in cash, Legacy accounts for unit options and UARs 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 and Unit Options 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, 2014 , Legacy issued 136,100 UARs to employees which vest ratably over a three -year period and 105,174 UARs to employees which vest at the end of a three -year period. During the six -month period ended June 30, 2015 , Legacy issued 21,500 UARs to employees which vest ratably over a three -year period. All UARs granted in 2014 and 2015 expire seven years from the grant date and are exercisable when they vest. For the six -month periods ended June 30, 2015 and 2014 , Legacy recorded $16,359 and $256,674 , respectively, of compensation expense due to the change in liability from December 31, 2014 and 2013 , respectively, based on its use of the Black-Scholes model to estimate the June 30, 2015 and 2014 fair value of these UARs (see Note 6). As of June 30, 2015 , there was a total of approximately $16,867 of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At June 30, 2015 , this cost was expected to be recognized over a weighted-average period of approximately 2.24 years. Compensation expense is based upon the fair value as of June 30, 2015 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 41% and employed the Black-Scholes model to estimate the June 30, 2015 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 4.7% . Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $1.40 per unit. A summary of UAR and unit option activity for the six months ended June 30, 2015 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2015 671,229 $ 26.97 Granted 21,500 11.12 Forfeited (9,300 ) 24.42 Outstanding at June 30, 2015 683,429 $ 26.51 4.7 $ — Options and UARs exercisable at June 30, 2015 272,719 $ 25.80 3.4 $ — The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2015 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2015 451,173 $ 27.69 Granted 21,500 11.12 Vested (52,663 ) 27.04 Forfeited (9,300 ) 24.42 Non-vested at June 30, 2015 410,710 $ 26.98 Legacy has used a weighted-average risk-free interest rate of 1.5% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at June 30, 2015 whose terms are consistent with the expected life of the UARs and unit options. Expected life represents the period of time that UARs and unit options 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) 4.71 Risk free interest rate 1.5 % Annual distribution rate per unit $1.40 Volatility 41 % Phantom Units Legacy has also issued phantom units under the LTIP to both executive officers, as described below, and certain other employees. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive one Partnership unit for each phantom unit. Legacy is accounting for these phantom units by utilizing the equity 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 March 4, 2014 , the Compensation Committee approved the award of 117,197 subjective, or service-based, phantom units and 102,572 objective, or performance based, phantom units to Legacy’s executive officers. 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. Compensation expense related to the phantom units and associated DERs was $1.4 million and $1.0 million for the six months ended June 30, 2015 and 2014 , respectively. Restricted Units During the year ended December 31, 2014 , Legacy issued an aggregate of 127,845 restricted units to non-executive employees. These restricted units awarded typically vest ratably over a three -year period all beginning on or around the date of grant. During the six -month period ended June 30, 2015 , Legacy issued an aggregate of 326,160 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. 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. Compensation expense related to restricted units was $1.2 million and $1.1 million for the six months ended June 30, 2015 and 2014 , respectively. As of June 30, 2015 , there was a total of $6.1 million of unrecognized compensation expense related to the unvested portion of these restricted units. At June 30, 2015 , this cost was expected to be recognized over a weighted-average period of 2.6 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at June 30, 2015 , do not include 508,830 units related to unvested restricted unit awards. Board Units On May 15, 2014, Legacy granted and issued 3,628 units to each of its five non-employee directors. The value of each unit was $27.50 at the time of issuance. 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.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2015
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors On April 2, 2014, we 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, our 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 our 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 our 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., which constitute all of our 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 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.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On July 2, 2015, Legacy entered into a Development Agreement (the “Development Agreement”) with Jupiter JV, LP (“Investor”), which was formed by certain of TPG Special Situations Partners’ investment funds. Pursuant to the Development Agreement, Legacy and Investor will participate in the funding, exploration, development and operation of certain of Legacy’s currently undeveloped oil and gas properties covering approximately 6,000 net acres, restricted to certain depths, located in the University Block, RTF Block and Lea Hamon Block in the Permian Basin (collectively, the “Subject Assets”). Concurrently with the Development Agreement, Legacy and Investor entered into an Asset Acquisition Agreement pursuant to which Legacy conveyed to Investor an undivided 87.5% of Legacy's working interest in the Subject Assets subject to re-assignment, reversion and other adjustments. Legacy and Investor will establish tranches of proposed horizontal locations, with Investor funding 95% of Legacy's drilling and completion costs and receiving 87.5% of certain of Legacy's interests in any wells in such tranche until it achieves a 1.0 x return on investment ("ROI Hurdle"). Legacy will fund 5% of the drilling and completion costs and retain 12.5% of certain of its interests prior to the ROI Hurdle. Upon achievement of the ROI Hurdle, Investor will revert to 63% of Legacy's initial interest while Legacy will revert to 37% until Investor achieves a 15% internal rate of return ("IRR Hurdle"). Upon achievement of the IRR Hurdle, Investor will revert to 15% of Legacy's initial interest while Legacy will revert to 85% , and all the remaining undeveloped interests will revert to Legacy but remain available for future development under the Development Agreement. On July 3, 2015, Legacy entered into a Membership Interest Purchase and Sale Agreement (the “WGR Purchase Agreement”) with WGR Operating LP (“WGR”), a subsidiary of Western Gas Partners LP, which is a master limited partnership formed by Anadarko Petroleum Corporation. Pursuant to the WGR Purchase Agreement, Legacy acquired from WGR 100% of the issued and outstanding limited liability company membership interests in Dew Gathering LLC, a Texas limited liability company, which owns directly and indirectly natural gas gathering and processing assets (the “G&P Assets”) in Anderson, Freestone, Houston, Leon, Limestone and Robertson Counties, Texas, for a purchase price of $154 million , subject to customary adjustments. In addition, on July 3, 2015, Legacy entered into a Purchase and Sale Agreement (together with the “WGR Purchase Agreement,” the “Agreements”) with Anadarko E&P Onshore LLC (“Anadarko”), a subsidiary of Anadarko Petroleum Corporation, pursuant to which Legacy acquired various oil and natural gas properties and associated exploration and production assets (the “E&P Assets”) from Anadarko for a purchase price of $286 million , subject to customary adjustments. The G&P Assets service the E&P Assets. Both the WGR and Anadarko purchases closed on July 31, 2015 and were funded with borrowings under Legacy's revolving credit facility. Legacy is currently determining the fair value of assets acquired and liabilities assumed in each purchase. On July 21, 2015, Legacy’s board of directors approved a distribution of $0.35 per unit payable on August 14, 2015 to unitholders of record on July 31, 2015. On July 21, 2015, Legacy announced that its general partner had declared a monthly cash distribution for both its Series A Preferred Units and its Series B Preferred Units of $0.166667 per unit payable on August 17, 2015 to unitholders of record on August 3, 2015. On August 5, 2015, Legacy entered into the Fifth Amendment to the Current Credit Agreement (the “Fifth Amendment”). Pursuant to the Fifth Amendment, the borrowing base under the Current Credit Agreement was increased from $700 million to $950 million and an additional lender was added to the agreement. As of August 5, 2015 , Legacy had approximately $554 million drawn under the Current Credit Agreement, leaving approximately $396 million of current availability.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
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, 2015 and for the three and six months ended June 30, 2015 and 2014 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, 2014 .
Recent Accounting Pronouncements	Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 will become effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not expect the adoption of ASU 2015-03 will have a material impact 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. On July 9, 2015, the FASB approved a one-year delay of the standard's effective date. Therefore, 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 Accoun21

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 and December 31, 2014 : June 30, December 31, (In thousands) Revenue payable $ 15,660 $ 19,267 Accrued lease operating expense 17,861 21,177 Accrued capital expenditures 3,870 20,773 Accrued ad valorem tax 10,709 9,382 Other 6,567 8,016 $ 54,667 $ 78,615

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following as of June 30, 2015 and December 31, 2014 : June 30, December 31, 2015 2014 (In thousands) Credit Facility due 2019 $ 135,000 $ 109,000 8% Senior Notes due 2020 300,000 300,000 6.625% Senior Notes due 2021 550,000 550,000 985,000 959,000 Unamortized discount on Senior Notes (18,889 ) (20,124 ) Total Long-Term Debt $ 966,111 $ 938,876
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 % 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, 2015
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 WPX Acquisition 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 $ 403,980 Future abandonment costs (43,989 ) Fair value of net assets acquired $ 359,991
Schedule of unaudited pro forma results of operations	The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013. 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, 2014 2014 (In thousands) Revenues $ 153,518 $ 301,270 Net loss attributable to unitholders $ (21,722 ) $ (16,091 ) Loss per unit — basic and diluted $ (0.38 ) $ (0.28 ) Units used in computing income (loss) per unit: Basic and diluted 57,372 57,341

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 : Fair Value Measurements at June 30, 2015 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, 2015 (In thousands) LTIP liability (a) $ — $ (28 ) $ — $ (28 ) Oil and natural gas derivatives — 87,367 (4,811 ) 82,556 Interest rate swaps — (985 ) — (985 ) Total $ — $ 86,354 $ (4,811 ) $ 81,543 (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, 2015 2014 2015 2014 (In thousands) Beginning balance $ (2,485 ) $ 14,552 $ 555 $ 20,615 Transfers(a) — (14,552 ) — (14,552 ) Total losses (3,275 ) — (6,632 ) (6,740 ) Settlements, net 949 — 1,266 677 Ending balance $ (4,811 ) $ — $ (4,811 ) $ — Losses included in earnings relating to derivatives still held as of June 30, 2015 and 2014 $ (3,492 ) $ — $ (4,811 ) $ — (a) As part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments, with the exception of Midland-Cushing crude oil differential swaps, previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) were transfered to Level 2 instruments during the period ended March 31, 2014.
Schedule of fair value measurements of proved oil and natural gas properties	Assets measured at fair value during the six -month period ended June 30, 2015 include: Fair Value Measurements During the Six Months Ended June 30, 2015 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) $ — $ — $ 198,095 Acquisitions (b) $ — $ — $ 1,923 (a) Legacy reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be 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. During the six -month period ended June 30, 2015 , Legacy incurred impairment charges of $209.4 million as oil and natural gas properties with a net cost basis of $407.5 million were written down to their fair value of $198.1 million . In order to determine fair value, 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. (b) Assets and liabilities acquired in a business combination are recorded at fair value. During the six -month period ended June 30, 2015 , Legacy acquired oil and natural gas properties, inclusive of unproved acreage acquisitions, with a fair value of $1.9 million in multiple individually immaterial transactions. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. 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. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 and 2014 : Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Beginning fair value of commodity derivatives $ 133,242 $ 5,397 $ 153,099 $ 17,673 Total gain (loss) - oil derivatives (12,649 ) (33,770 ) 945 (46,030 ) Total gain (loss) - natural gas derivatives (848 ) 2,337 6,038 (1,289 ) Crude oil derivative cash settlements paid (received) (27,364 ) 6,244 (59,564 ) 8,800 Natural gas derivative cash settlements paid (received) (9,825 ) (234 ) (17,962 ) 820 Ending fair value of commodity derivatives $ 82,556 $ (20,026 ) $ 82,556 $ (20,026 )
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, 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 $ 136,664 $ (54,108 ) $ 82,556 Total derivative assets $ 136,664 $ (54,108 ) $ 82,556 Offsetting Derivative Liabilities: Commodity derivatives $ (54,108 ) $ 54,108 $ — Interest rate derivatives (985 ) — (985 ) Total derivative liabilities $ (55,093 ) $ 54,108 $ (985 ) December 31, 2014 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 $ 223,778 $ (70,679 ) $ 153,099 Total derivative assets $ 223,778 $ (70,679 ) $ 153,099 Offsetting Derivative Liabilities: Commodity derivatives $ (70,679 ) $ 70,679 $ — Interest rate derivatives (2,080 ) — (2,080 ) Total derivative liabilities $ (72,759 ) $ 70,679 $ (2,080 )
Schedule of notional amounts of outstanding derivative positions	As of June 30, 2015 , 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 Time Period Volumes (Bbls) Price per Bbl Price Range per Bbl July-December 2015 282,522 $79.51 $52.00 - $99.85 2016 228,600 $87.94 $86.30 - $99.85 2017 182,500 $84.75 $84.75 As of June 30, 2015 , 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 Time Period Volumes (Bbls) Price per Bbl Price Range per Bbl July-December 2015 1,656,000 $(1.78) $(1.75) - $(1.90) 2016 2,928,000 $(1.60) $(1.50) - $(1.75) As of June 30, 2015 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long put, a short put and 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 2015 673,440 $64.78 $89.78 $110.57 2016 621,300 $63.37 $88.37 $106.40 2017 72,400 $60.00 $85.00 $104.20 As of June 30, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and 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 2016 183,000 $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, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and a fixed-price swap as indicated below: Average Short Put Average Swap Time Period Volumes (Bbls) Price per Bbl Price per Bbl July-December 2015 506,000 $77.73 $93.98 As of June 30, 2015 , Legacy had the following NYMEX Henry Hub, West Texas Waha, ANR-OK and CIG-Rockies 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 2015 11,706,400 $4.13 $3.11 - $5.82 2016 23,019,200 $3.43 $3.32 - $5.30 2017 21,600,000 $3.37 $3.32 - $3.39 2018 21,600,000 $3.37 $3.32 - $3.39 2019 19,800,000 $3.38 $3.38 - $3.39 As of June 30, 2015 , 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 2015 4,020,000 $3.66 $4.21 $5.01 2016 5,580,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of June 30, 2015 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, NGPL Midcon, California SoCal NGI, San Juan Basin and West Texas WAHA 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 2015 Average Volumes (MMBtu) Price per MMBtu NWPL 6,000,000 $(0.13) NGPL 240,000 $(0.15) SoCal 120,000 $0.19 San Juan 240,000 $(0.12) WAHA 3,000,000 $(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, 2015 2014 2015 2014 (In thousands) Beginning fair value of interest rate swaps $ (1,540 ) $ (4,047 ) $ (2,080 ) $ (4,759 ) Total loss on interest rate swaps (143 ) (109 ) (291 ) (283 ) Cash settlements paid 698 824 1,386 1,710 Ending fair value of interest rate swaps $ (985 ) $ (3,332 ) $ (985 ) $ (3,332 )
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap position as of June 30, 2015 : Estimated Fair Market Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2015 (Dollars in thousands) $ 29,000 3.070 % 10/16/2007 10/16/2015 $ (277 ) $ 13,000 3.112 % 11/16/2007 11/16/2015 (160 ) $ 12,000 3.131 % 11/28/2007 11/28/2015 (149 ) $ 50,000 2.500 % 10/10/2008 10/10/2015 (399 ) Total fair market value of interest rate derivatives $ (985 )

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 and year ended December 31, 2014 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 226,525 $ 175,786 Liabilities incurred with properties acquired 18,756 50,487 Liabilities incurred with properties drilled — 941 Liabilities settled during the period (1,271 ) (2,918 ) Liabilities associated with properties sold (4,572 ) (5,891 ) Current period accretion 5,201 8,120 Asset retirement obligation - end of period $ 244,639 $ 226,525

Partners' Equity (Tables)

Partners' Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [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, 2015 2014 2015 2014 (In thousands) Net loss $ (38,474 ) $ (16,488 ) $ (267,328 ) $ (15,960 ) Distributions to preferred unitholders (4,750 ) (2,194 ) (9,500 ) (2,194 ) Net loss available to unitholders (43,224 ) (18,682 ) (276,828 ) (18,154 ) Weighted average number of units outstanding 68,897 57,372 68,909 57,341 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 68,897 57,372 68,909 57,341 Basic and diluted loss per unit $ (0.63 ) $ (0.33 ) $ (4.02 ) $ (0.32 )

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of option and UAR activity	A summary of UAR and unit option activity for the six months ended June 30, 2015 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2015 671,229 $ 26.97 Granted 21,500 11.12 Forfeited (9,300 ) 24.42 Outstanding at June 30, 2015 683,429 $ 26.51 4.7 $ — Options and UARs exercisable at June 30, 2015 272,719 $ 25.80 3.4 $ —
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, 2015 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2015 451,173 $ 27.69 Granted 21,500 11.12 Vested (52,663 ) 27.04 Forfeited (9,300 ) 24.42 Non-vested at June 30, 2015 410,710 $ 26.98
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) 4.71 Risk free interest rate 1.5 % Annual distribution rate per unit $1.40 Volatility 41 %

Summary of Significant Accoun29

Summary of Significant Accounting Policies - Other Narrative (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2013
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	66.667%
Term of right to receive information reasonably required for tax reporting purposes after close of year	90 days

Summary of Significant Accoun30

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue payable	$ 15,660	$ 19,267
Accrued lease operating expense	17,861	21,177
Accrued capital expenditures	3,870	20,773
Accrued ad valorem tax	10,709	9,382
Other	6,567	8,016
Accrued oil and natural gas liabilities	$ 54,667	$ 78,615

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	May. 13, 2014	May. 28, 2013
Debt Instrument [Line Items]
Long-term debt, gross	$ 985,000	$ 959,000
Unamortized discount on Senior Notes	(18,889)	(20,124)
Total Long-Term Debt	$ 966,111	938,876
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate	8.00%
Long-term debt, gross	$ 300,000	300,000
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Stated interest rate	6.625%
Long-term debt, gross	$ 550,000	550,000	$ 300,000	$ 250,000
Credit facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 135,000	$ 109,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility (Details)	Apr. 02, 2014USD ($)	Mar. 10, 2011USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 985,000,000	$ 959,000,000
Credit Facility due 2016
Line of Credit Facility [Line Items]
Expiration period		5 years
Current borrowing capacity		$ 1,000,000,000
Credit facility due 2019
Line of Credit Facility [Line Items]
Expiration period	5 years
Maximum borrowing capacity	$ 1,500,000,000		700,000,000
Minimum percent of total value securing credit agreement	80.00%
Purchase price of properties as a percentage of borrowing base required for potential re-determination of borrowing base, minimum	10.00%
Minimum percent of outstanding principal amount required for changes to credit agreement	66.6667%
Long-term debt, gross			$ 135,000,000	$ 109,000,000
Interest rate at period end			1.69%
Remaining borrowing capacity			$ 564,900,000
Interest Paid			$ 2,400,000
Credit facility due 2019 | Maximum
Line of Credit Facility [Line Items]
Ratio of indebtedness to EBITDA			2.5
Credit facility due 2019 | Minimum
Line of Credit Facility [Line Items]
Ratio of indebtedness to EBITDA				2.5
Ratio of unused amount of total commitments to consolidated current liabilities			1
Credit facility due 2019 | one-, two-, three- or six-month LIBOR [Member] | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.50%
Credit facility due 2019 | one-, two-, three- or six-month LIBOR [Member] | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
Credit facility due 2019 | Alternate Base Rate, Federal Funds [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Credit facility due 2019 | Alternate Base Rate, one-month LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Credit facility due 2019 | Standard Alternate Base Rate [Member] | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
Credit facility due 2019 | Standard Alternate Base Rate [Member] | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000

Long-Term Debt - Senior Notes (

Long-Term Debt - Senior Notes (Details) - USD ($) $ in Thousands	May. 13, 2014	May. 28, 2013	Dec. 04, 2012	Jun. 30, 2015	Dec. 31, 2013	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, gross				$ 985,000		$ 959,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate				8.00%
Long-term debt, gross				$ 300,000		$ 300,000
Issuance percent of par			97.848%
Percent of notes eligible of early redemption						35.00%
Senior notes | 8% Senior Notes due 2020 | Company Option [Member]
Debt Instrument [Line Items]
Redemption price percentage				108.00%
Senior notes | 8% Senior Notes due 2020 | Change in Control [Member]
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%
Long-term debt, gross	$ 300,000	$ 250,000		$ 550,000		$ 550,000
Issuance percent of par	99.00%	98.405%
Percent of notes eligible of early redemption				35.00%
Senior notes | 6.625% Senior Notes due 2021 | Company Option [Member]
Debt Instrument [Line Items]
Redemption price percentage				106.625%
Senior notes | 6.625% Senior Notes due 2021 | Change in Control [Member]
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%

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 04, 2014	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 03, 2014
Incentive Distribution Equity
Business Acquisition [Line Items]
Incentive Distribution Units issued in exchange for oil and natural gas properties			$ 30,800
WPX acquisition
Business Acquisition [Line Items]
Acquisition purchase price	$ 360,000
Equity interests issuable (in shares)	300,000
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					$ 403,980
Future abandonment costs					(43,989)
Fair value of net assets acquired					$ 359,991
Pro Forma Operating Results
Revenues		$ 153,518		$ 301,270
Net loss attributable to unitholders		$ (21,722)		$ (16,091)
Loss per unit - basic and diluted (in dollars per share)		$ (0.38)		$ (0.28)
Basic and diluted (in shares)		57,372,000		57,341,000
WPX acquisition | Immediate vesting
Business Acquisition [Line Items]
Equity interests issuable (in shares)	100,000

Related Party Transactions (Det

Related Party Transactions (Details) - 6 months ended Jun. 30, 2015 - President/CEO and Director, EVP, CDO - USD ($)	Total
Related Party Transaction [Line Items]
Noncontrolling ownership interest in third party by related party	4.16%
Monthly rent expense	$ 66,120

Commitments and Contingencies (

Commitments and Contingencies (Details) - Jun. 30, 2015 $ in Millions	USD ($)$ / MMBTU
Loss Contingencies [Line Items]
Purchase obligation calculated floor price | $ / MMBTU	57.14
Estimated total future purchase obligation	$ 58.5
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 ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	May. 13, 2014	May. 28, 2013
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	$ 1,398,183		$ 1,398,183		$ 1,639,974
Impairment of long-lived assets			209,400
Long-term debt, gross	985,000		985,000		959,000
Credit facility due 2019
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	135,000		135,000		109,000
Senior notes | 8% Senior Notes due 2020
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	300,000		300,000		300,000
Senior notes | 6.625% Senior Notes due 2021
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	550,000		550,000		$ 550,000	$ 300,000	$ 250,000
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	260,700		260,700
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	440,000		440,000
Recurring
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	(28)		(28)
Fair value of assets (liabilities)	81,543		81,543
Recurring | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative asset	82,556		82,556
Recurring | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability	(985)		(985)
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
Fair value of assets (liabilities)	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
Derivative asset	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
Derivative liability	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	(28)		(28)
Fair value of assets (liabilities)	86,354		86,354
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
Derivative asset	87,367		87,367
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
Derivative liability	(985)		(985)
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
Fair value of assets (liabilities)	(4,811)		(4,811)
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance	(2,485)	$ 14,552	555	$ 20,615
Transfers	0	(14,552)	0	(14,552)
Total losses	(3,275)	0	(6,632)	(6,740)
Settlements, net	949	0	1,266	677
Ending balance	(4,811)	0	(4,811)	0
Losses included in earnings relating to derivatives still held as of June 30, 2015 and 2014			(4,811)	$ 0
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Losses included in earnings relating to derivatives still held as of June 30, 2015 and 2014	(3,492)	$ 0
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
Derivative asset	(4,811)		(4,811)
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
Derivative liability	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
Acquisitions			0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	0		0
Acquisitions			0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	198,095		198,095
Acquisitions			1,923
Oil and gas properties, gross	$ 407,500		$ 407,500

Derivative Financial Instrume38

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives			$ 8,078	$ (45,893)
Derivative cash settlements paid (received)			(77,526)	9,620
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of interest rate swaps	$ 133,242	$ 5,397	153,099	17,673
Ending fair value of interest rate swaps	82,556	(20,026)	82,556	(20,026)
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(12,649)	(33,770)	945	(46,030)
Derivative cash settlements paid (received)	(27,364)	6,244	(59,564)	8,800
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(848)	2,337	6,038	(1,289)
Derivative cash settlements paid (received)	$ (9,825)	$ (234)	$ (17,962)	$ 820

Derivative Financial Instrume39

Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	$ 136,664	$ 223,778
Gross Amounts Offset in the Consolidated Balance Sheets	(54,108)	(70,679)
Net Amounts Presented in the Consolidated Balance Sheets	82,556	153,099
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(55,093)	(72,759)
Gross Amounts Offset in the Consolidated Balance Sheets	54,108	70,679
Net Amounts Presented in the Consolidated Balance Sheets	(985)	(2,080)
Commodity contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	136,664	223,778
Gross Amounts Offset in the Consolidated Balance Sheets	(54,108)	(70,679)
Net Amounts Presented in the Consolidated Balance Sheets	82,556	153,099
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(54,108)	(70,679)
Gross Amounts Offset in the Consolidated Balance Sheets	54,108	70,679
Net Amounts Presented in the Consolidated Balance Sheets	0	0
Interest rate contract
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(985)	(2,080)
Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Net Amounts Presented in the Consolidated Balance Sheets	$ (985)	$ (2,080)

Derivative Financial Instrume40

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details) $ in Thousands	Jun. 30, 2015USD ($)MMBTUbbl$ / bbl$ / MMBTU	Sep. 30, 2014MMBTU$ / MMBTU
NYMEX WTI Swaps | Crude Oil | July-December 2015
Derivative [Line Items]
Volumes | bbl	282,522
Average Price	79.51
NYMEX WTI Swaps | Crude Oil | July-December 2015 | Minimum
Derivative [Line Items]
Price Range	52
NYMEX WTI Swaps | Crude Oil | July-December 2015 | Maximum
Derivative [Line Items]
Price Range	99.85
NYMEX WTI Swaps | Crude Oil | 2016
Derivative [Line Items]
Volumes | bbl	228,600
Average Price	87.94
NYMEX WTI Swaps | Crude Oil | 2016 | Minimum
Derivative [Line Items]
Price Range	86.30
NYMEX WTI Swaps | Crude Oil | 2016 | Maximum
Derivative [Line Items]
Price Range	99.85
NYMEX WTI Swaps | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	182,500
Average Price	84.75
NYMEX WTI Swaps | Crude Oil | 2017 | Minimum
Derivative [Line Items]
Price Range	84.75
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | July-December 2015
Derivative [Line Items]
Volumes | bbl	1,656,000
Average Price	(1.78)
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | July-December 2015 | Minimum
Derivative [Line Items]
Price Range	(1.75)
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | July-December 2015 | Maximum
Derivative [Line Items]
Price Range	(1.90)
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | 2016
Derivative [Line Items]
Volumes | bbl	2,928,000
Average Price	(1.60)
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | 2016 | Minimum
Derivative [Line Items]
Price Range	(1.50)
Midland-to-Cushing Differential Swaps [Member] | Crude Oil | 2016 | Maximum
Derivative [Line Items]
Price Range	(1.75)
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2015
Derivative [Line Items]
Volumes | bbl	673,440
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2015 | Put option | Short
Derivative [Line Items]
Average Strike Price	64.78
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2015 | Put option | Long
Derivative [Line Items]
Average Strike Price	89.78
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2015 | Call option | Short
Derivative [Line Items]
Average Strike Price	110.57
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016
Derivative [Line Items]
Volumes | bbl	621,300
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price	63.37
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price	88.37
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Call option | Short
Derivative [Line Items]
Average Strike Price	106.40
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	72,400
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price	60
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price	85
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Call option | Short
Derivative [Line Items]
Average Strike Price	104.20
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016
Derivative [Line Items]
Volumes | bbl	183,000
Average Price	91.70
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	182,500
Average Price	90.85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	127,750
Average Price	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 2 | Crude Oil | July-December 2015
Derivative [Line Items]
Volumes | bbl	506,000
Average Price	93.98
NYMEX WTI Enhanced Swap Contracts 2 | Crude Oil | July-December 2015 | Put option | Short
Derivative [Line Items]
Average Strike Price	77.73
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU	11,706,400
Average Price | $ / MMBTU	4.13
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2015 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.11
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2015 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	5.82
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2016
Derivative [Line Items]
Volumes | MMBTU	23,019,200
Average Price | $ / MMBTU	3.43
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2016 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.32
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 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	21,600,000
Average Price | $ / MMBTU	3.37
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2017 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.32
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	21,600,000
Average Price | $ / MMBTU	3.37
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2018 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.32
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	19,800,000
Average Price | $ / MMBTU	3.38
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.38
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 2015
Derivative [Line Items]
Volumes | MMBTU	4,020,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2015 | Put option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.66
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2015 | Put option | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.21
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2015 | Call option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.01
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016
Derivative [Line Items]
Volumes | MMBTU	5,580,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Call option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.08
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	5,040,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Call option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.53
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU		6,000,000
Average Price | $ / MMBTU		(0.13)
Henry Hub NYMEX to NGPL Midcon Natural Gas Differential Swaps [Member] | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU		240,000
Average Price | $ / MMBTU		(0.15)
Interest rate swaps | Libor Swap All Tranches [Member]
Derivative [Line Items]
Estimated Fair Market Value | $	$ (985)
Interest rate swaps | Libor Swap Tranche 1
Derivative [Line Items]
Notional Amount | $	$ 29,000
Fixed Rate	3.07%
Estimated Fair Market Value | $	$ (277)
Interest rate swaps | Libor Swap Tranche 2
Derivative [Line Items]
Notional Amount | $	$ 13,000
Fixed Rate	3.112%
Estimated Fair Market Value | $	$ (160)
Interest rate swaps | Libor Swap Tranche 3
Derivative [Line Items]
Notional Amount | $	$ 12,000
Fixed Rate	3.1312%
Estimated Fair Market Value | $	$ (149)
Interest rate swaps | Libor Swap Tranche 4
Derivative [Line Items]
Notional Amount | $	$ 50,000
Fixed Rate	2.50%
Estimated Fair Market Value | $	$ (399)
Henry Hub NYMEX to California SoCal NGI Natural Gas Differential Swaps [Member] | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU		120,000
Average Price | $ / MMBTU		0.19
Henry Hub NYMEX to San Juan Basin Natural Gas Differential Swaps [Member] | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU		240,000
Average Price | $ / MMBTU		(0.12)
Henry Hub NYMEX to West Texas WAHA Natural Gas Differential Swaps [Member] | Natural gas | July-December 2015
Derivative [Line Items]
Volumes | MMBTU		3,000,000
Average Price | $ / MMBTU		(0.10)

Derivative Financial Instrume41

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements paid			$ (77,526)	$ 9,620
Interest rate swaps | Not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Beginning fair value of interest rate swaps	$ (1,540)	$ (4,047)	(2,080)	(4,759)
Cash settlements paid	698	824	1,386	1,710
Ending fair value of interest rate swaps	(985)	(3,332)	(985)	(3,332)
Interest rate swaps | Not designated as hedging instrument | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Total loss on interest rate swaps	$ (143)	$ (109)	$ (291)	$ (283)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Changes in the ARO
Asset retirement obligation — beginning of period	$ 226,525	$ 175,786
Liabilities incurred with properties acquired	18,756	50,487
Liabilities incurred with properties drilled	0	941
Liabilities settled during the period	(1,271)	(2,918)
Liabilities associated with properties sold	(4,572)	(5,891)
Current period accretion	5,201	8,120
Asset retirement obligation — end of period	$ 244,639	$ 226,525

Partners' Equity - Preferred Un

Partners' Equity - Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	Jul. 01, 2014	Jun. 17, 2014	Jun. 04, 2014	May. 12, 2014	Apr. 17, 2014	Jun. 30, 2015
Class of Stock [Line Items]
Liquidation preference (in dollars per share)						$ 25
WPX acquisition
Class of Stock [Line Items]
Equity interests issuable (in shares)			300,000
Conversion terms, minimum distribution per share			$ 0.90
WPX acquisition | Immediate vesting
Class of Stock [Line Items]
Equity interests issuable (in shares)			100,000
WPX acquisition | Ratable vesting
Class of Stock [Line Items]
Equity interests issuable (in shares)			10,000
Additional cash consideration			$ 35.5
WPX acquisition | Forfeiture, first two anniversaries
Class of Stock [Line Items]
Equity interests forfeiture (in shares)			66,666
WPX acquisition | Forfeiture, third anniversary
Class of Stock [Line Items]
Equity interests forfeiture (in shares)			66,668
Series A Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)					2,000,000
Share price					$ 25
Dividend rate						8.00%
Additional shares of underwriter purchase option				300,000
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		$ 25
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
Unvested IDUs [Member] | WPX acquisition
Class of Stock [Line Items]
Equity interests issuable (in shares)			200,000

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, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share [Abstract]
Net loss	$ (38,474)	$ (16,488)	$ (267,328)	$ (15,960)
Distributions to preferred unitholders	4,750	2,194	9,500	2,194
Net loss available to unitholders	$ (43,224)	$ (18,682)	$ (276,828)	$ (18,154)
Weighted average number of units outstanding (in shares)	68,897,000	57,372,000	68,909,000	57,341,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	0	0
Weighted average units and potential common units outstanding (in shares)	68,897,000	57,372,000	68,909,000	57,341,000
Basic and diluted loss per unit (in dollars per share)	$ (0.63)	$ (0.33)	$ (4.02)	$ (0.32)
Phantom share units (PSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS	862,064	323,965	862,064	323,965
Restricted stock units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS	508,830	264,097	508,830	264,097

Unit-Based Compensation - LTIP,

Unit-Based Compensation - LTIP, Unit Appreciation Rights and Unit Options (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Jun. 11, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual interest rate	1.50%
Unit appreciation rights (UARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation. gross	21,500
Unit award expiration period	7 years
Share-based compensation expense	$ 16,359	$ 256,674
Unrecognized compensation costs	$ 16,867
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 2 months 28 days
Volatility	41.00%
Share based compensation, forfeiture rate	4.70%
Annual distribution rate per unit (in dollars per share)	$ 1.4
Annual interest rate	1.50%
Unit appreciation rights (UARs) | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation. gross	21,500		136,100
Award vesting period	3 years		3 years
Unit appreciation rights (UARs) | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation. gross			105,174
Award vesting period			3 years
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,200,000	1,100,000
Unrecognized compensation costs	$ 6,100,000
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 6 months 24 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,400,000	$ 1,000,000
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)	2,180,140
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)	855,534
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)	862,064
Long Term Incentive Plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	196,528

Unit-Based Compensation - Optio

Unit-Based Compensation - Option and UAR Activity (Details) - Unit appreciation rights (UARs) - USD ($)	6 Months Ended
	Jun. 30, 2015
Units (in shares)
Outstanding	671,229
Granted	21,500
Forfeited	(9,300)
Outstanding	683,429
Options and UARs exercisable	272,719
Weighted-Average Exercise Price (in dollars per share)
Outstanding	$ 26.97
Granted	11.12
Forfeited	24.42
Outstanding	26.51
Options and UARs exercisable	$ 25.80
Weighted-Average Remaining Contractual Term
Outstanding	4 years 8 months 17 days
Options and UARs exercisable	3 years 4 months 8 days
Aggregate Intrinsic Value
Outstanding	$ 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) - $ / shares	6 Months Ended
	Jun. 30, 2015
Number of Units
Non-vested at January 1, 2015	451,173
Granted	21,500
Vested	(52,663)
Forfeited	(9,300)
Non-vested at June 30, 2015	410,710
Weighted- Average Exercise Price
Non-vested at January 1, 2015	$ 27.69
Granted	11.12
Vested	27.04
Forfeited	24.42
Non-vested at June 30, 2015	$ 26.98

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - 6 months ended Jun. 30, 2015 - $ / shares	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual interest rate	1.50%
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	4 years 8 months 17 days
Annual interest rate	1.50%
Annual distribution rate per unit (in dollars per share)	$ 1.4
Volatility	41.00%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details)	Jun. 15, 2015director$ / sharesshares	Feb. 24, 2015shares	May. 15, 2014director$ / sharesshares	Mar. 04, 2014shares	Mar. 07, 2013	Sep. 21, 2009	Jun. 30, 2015USD ($)shares	Jun. 30, 2014USD ($)	Dec. 31, 2014shares
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)							21,500
Unvested units not included in consolidated balance sheet (in shares)							410,710		451,173
Share-based compensation expense | $							$ 16,359	$ 256,674
Unrecognized compensation costs | $							$ 16,867
Unrecognized compensation costs, period of recognition							2 years 2 months 28 days
Stock Appreciation Rights (SARs) [Member] | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period							3 years		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
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		341,251		117,197
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
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		102,572
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 | $							$ 1,400,000	1,000,000
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)							508,830
Share-based compensation expense | $							$ 1,200,000	$ 1,100,000
Unrecognized compensation costs | $							$ 6,100,000
Unrecognized compensation costs, period of recognition							2 years 6 months 24 days
Restricted stock units (RSUs) | Non-executive employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)									127,845
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		3 years
Restricted stock units (RSUs) | Non-executive employees and certain executives
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)							326,160
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 | Five-year full vest
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)	11,025		3,628
Individuals eligible for plan | director	6		5
Value of each unit at issuance (in dollars per share) | $ / shares	$ 9.13		$ 27.50

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) $ in Thousands	11 Months Ended
	May. 08, 2014offering	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)	May. 13, 2014USD ($)	Mar. 18, 2014USD ($)	May. 28, 2013USD ($)
Debt Instrument [Line Items]
Long-term debt, gross		$ 985,000	$ 959,000
Senior notes
Debt Instrument [Line Items]
Number of private offerings | offering	2
Aggregate principal amount					$ 250,000
Percent of subsidiaries owned		100.00%
6.625% Senior Notes due 2021 | Senior notes
Debt Instrument [Line Items]
Long-term debt, gross		$ 550,000	$ 550,000	$ 300,000		$ 250,000

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, a in Thousands	Jul. 03, 2015USD ($)	Jul. 02, 2015a	Aug. 05, 2015USD ($)	Aug. 04, 2015USD ($)	Jul. 21, 2015$ / shares	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)	Apr. 02, 2014USD ($)
Subsequent Event [Line Items]
Long-term debt, gross						$ 985,000,000	$ 959,000,000
Credit facility due 2019
Subsequent Event [Line Items]
Maximum borrowing capacity						700,000,000		$ 1,500,000,000
Long-term debt, gross						135,000,000	$ 109,000,000
Remaining borrowing capacity						$ 564,900,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions declared and paid (in dollars per share) | $ / shares					$ 0.35
Subsequent Event [Member] | Credit facility due 2019
Subsequent Event [Line Items]
Maximum borrowing capacity			$ 950,000,000	$ 700,000,000
Long-term debt, gross			554,000,000
Remaining borrowing capacity			$ 396,000,000
Subsequent Event [Member] | Preferred Unit Series A
Subsequent Event [Line Items]
Distributions declared and paid (in dollars per share) | $ / shares					0.166667
Subsequent Event [Member] | Preferred Unit Series B
Subsequent Event [Line Items]
Distributions declared and paid (in dollars per share) | $ / shares					$ 0.166667
Subsequent Event [Member] | Development Agreement [Member]
Subsequent Event [Line Items]
Undeveloped oil and gas properties (in acres) | a		6
Asset Acquisition Agreement, Working Interest		87.50%
Asset Acquisition Agreement, Investor Funding		95.00%
Asset Acquisition Agreement, ROI Hurdle		1
Asset Acquisition Agreement, Company Funding		5.00%
Asset Acquisition Agreement, Retention of Interest Prior to ROI Hurdle		12.50%
Asset Acquisition Agreement, Investor Interest, ROI Hurdle Achievement		63.00%
Asset Acquisition Agreement, Company Interest, ROI Hurdle Achievement		37.00%
Asset Acquisition Agreement, IRR Hurdle		15.00%
Asset Acquisition Agreement, Investor Interest, IRR Hurdle Achievement		15.00%
Asset Acquisition Agreement, Company Interest, IRR Hurdle Achievement		85.00%
Subsequent Event [Member] | WGR Purchase Agreement [Member]
Subsequent Event [Line Items]
Membership interests intended to acquire	100.00%
Acquisition purchase price	$ 154,000,000
Subsequent Event [Member] | Anadarko Purchase and Sale Agreement [Member]
Subsequent Event [Line Items]
Acquisition purchase price	$ 286,000,000

Uncategorized Items - lgcy-2015

Label	Element	Value
Income (Loss) from Equity Method Investments	us-gaap_IncomeLossFromEquityMethodInvestments	$ 191
Income (Loss) from Equity Method Investments	us-gaap_IncomeLossFromEquityMethodInvestments	24
Results of Operations, Depreciation, Depletion, Amortization and Accretion	us-gaap_ResultsOfOperationsDepreciationDepletionAmortizationAndAccretion	36,197
Results of Operations, Depreciation, Depletion, Amortization and Accretion	us-gaap_ResultsOfOperationsDepreciationDepletionAmortizationAndAccretion	38,537
Gain (Loss) on Disposition of Oil and Gas and Timber Property	us-gaap_GainLossOnSaleOfProperty	3,853
Gain (Loss) on Disposition of Oil and Gas and Timber Property	us-gaap_GainLossOnSaleOfProperty	934
Asset Impairment Charges	us-gaap_AssetImpairmentCharges	0
Asset Impairment Charges	us-gaap_AssetImpairmentCharges	$ 2,387