Legacy Reserves 10-Q 4 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 01, 2017
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	Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		72,880,260

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash	$ 1,214	$ 2,555
Accounts receivable, net:
Oil and natural gas	42,189	43,192
Joint interest owners	26,673	23,414
Other	401	2
Fair value of derivatives (Notes 4 and 5)	24,343	6,162
Prepaid expenses and other current assets (Note 1)	8,457	7,447
Total current assets	103,277	82,772
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,276,421	3,305,856
Unproved properties	22,287	13,448
Accumulated depletion, depreciation, amortization and impairment	(2,125,166)	(2,137,395)
Oil and natural gas properties using the successful efforts method, at cost	1,173,542	1,181,909
Other property and equipment, net of accumulated depreciation and amortization of $11,047 and $10,412, respectively	2,898	3,423
Operating rights, net of amortization of $5,567 and $5,369, respectively	1,449	1,648
Fair value of derivatives (Notes 4 and 5)	27,767	20,553
Other assets	8,452	8,874
Investments in equity method investees	658	647
Total assets	1,318,043	1,299,826
Current liabilities:
Accounts payable	8,983	9,092
Accrued oil and natural gas liabilities (Note 1)	61,767	53,248
Fair value of derivatives (Notes 4 and 5)	94	9,743
Asset retirement obligation (Note 6)	2,980	2,980
Other	9,016	11,546
Total current liabilities	82,840	86,609
Long-term debt (Note 2)	1,180,047	1,161,394
Asset retirement obligation (Note 6)	268,803	269,168
Fair value of derivatives (Notes 4 and 5)	0	4,091
Other long-term liabilities	643	643
Total liabilities	1,532,333	1,521,905
Commitments and contingencies (Note 3)
Partners' deficit (Note 7):
Limited partners' deficit - 72,559,430 and 72,056,097 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively	(474,412)	(482,200)
General partner's deficit (approximately 0.03%)	(145)	(146)
Total partners' deficit	(214,290)	(222,079)
Total liabilities and partners' deficit	1,318,043	1,299,826
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2017 and December 31, 2016
Partners' deficit (Note 7):
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2017 and December 31, 2016	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2017 and December 31, 2016
Partners' deficit (Note 7):
Preferred equity	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2017 and December 31, 2016
Partners' deficit (Note 7):
Preferred equity	$ 174,261	$ 174,261

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Other property and equipment, accumulated depreciation and amortization	$ 11,047	$ 10,412
Operating rights, amortization	$ 5,567	$ 5,369
Limited partners' equity, units issued (in shares)	72,559,430	72,056,097
Limited partners' equity, units outstanding (in shares)	72,559,430	72,056,097
General partner's equity, percent	0.03%	0.03%
Incentive Distribution Equity
Incentive distribution equity, units issued (in shares)	100,000	100,000
Incentive distribution equity, units outstanding (in shares)	100,000	100,000
Preferred Unit Series A
Preferred equity, units issued (in shares)	2,300,000	2,300,000
Preferred equity, units outstanding (in shares)	2,300,000	2,300,000
Preferred Unit Series B
Preferred equity, units issued (in shares)	7,200,000	7,200,000
Preferred equity, units outstanding (in shares)	7,200,000	7,200,000

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues:
Oil sales	$ 46,096	$ 41,272	$ 95,238	$ 71,592
Natural gas liquids (NGL) sales	4,921	3,922	9,971	6,375
Natural gas sales	41,830	28,173	87,185	61,259
Total revenues	92,847	73,367	192,394	139,226
Expenses:
Oil and natural gas production	44,802	44,561	96,019	94,584
Production and other taxes	4,145	3,390	8,304	5,963
General and administrative	8,581	10,993	19,133	20,427
Depletion, depreciation, amortization and accretion	27,689	37,668	56,485	74,627
Impairment of long-lived assets	1,821	0	9,883	15,447
(Gain) loss on disposal of assets	11,049	(9,141)	5,525	(40,842)
Total expenses	98,087	87,471	195,349	170,206
Operating loss	(5,240)	(14,104)	(2,955)	(30,980)
Other income (expense):
Interest income	8	16	9	54
Interest expense (Notes 2, 4 and 5)	(20,614)	(20,302)	(40,747)	(45,478)
Gain on extinguishment of debt (Note 2)	0	19,998	0	150,802
Equity in income (loss) of equity method investees	1	(9)	12	(14)
Net gains (losses) on commodity derivatives (Notes 4 and 5)	14,516	(37,675)	49,185	(20,637)
Other	402	(98)	362	(192)
Income (loss) before income taxes	(10,927)	(52,174)	5,866	53,555
Income tax expense	(150)	(87)	(571)	(487)
Net income (loss)	(11,077)	(52,261)	5,295	53,068
Distributions to preferred unitholders	(4,750)	(4,750)	(9,500)	(8,708)
Net income (loss) attributable to unitholders	$ (15,827)	$ (57,011)	$ (4,205)	$ 44,360
Income (loss) per unit - basic and diluted (in dollars per share) (Note 7)	$ (0.22)	$ (0.81)	$ (0.06)	$ 0.64
Weighted average number of units used in computing net income (loss) per unit -
Basic and diluted (in shares)	72,354	70,071	72,229	69,518

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Partners' Deficit (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2017
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance		$ (222,079)
Units issued to Legacy Board of Directors for services		586
Unit-based compensation		$ 1,908
Vesting of restricted and phantom units (in units)		0
Net income	$ (11,077)	$ 5,295
Unitholders equity, ending balance	$ (214,290)	$ (214,290)
Preferred Equity | Series A Preferred Equity
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		2,300
Unitholders equity, beginning balance		$ 55,192
Unitholders equity, ending balance (in units)	2,300	2,300
Unitholders equity, ending balance	$ 55,192	$ 55,192
Preferred Equity | Series B Preferred Equity
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		7,200
Unitholders equity, beginning balance		$ 174,261
Unitholders equity, ending balance (in units)	7,200	7,200
Unitholders equity, ending balance	$ 174,261	$ 174,261
Incentive Distribution Equity
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		100
Unitholders equity, beginning balance		$ 30,814
Unitholders equity, ending balance (in units)	100	100
Unitholders equity, ending balance	$ 30,814	$ 30,814
Partners' Deficit | Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		72,056
Unitholders equity, beginning balance		$ (482,200)
Units issued to Legacy Board of Directors for services (in units)		287
Units issued to Legacy Board of Directors for services		$ 586
Unit-based compensation		$ 1,908
Vesting of restricted and phantom units (in units)		216
Net income		$ 5,294
Unitholders equity, ending balance (in units)	72,559	72,559
Unitholders equity, ending balance	$ (474,412)	$ (474,412)
Partners' Deficit | General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance		(146)
Net income		1
Unitholders equity, ending balance	$ (145)	$ (145)

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash flows from operating activities:
Net income	$ 5,295	$ 53,068
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	56,485	74,627
Amortization of debt discount and issuance costs	3,713	6,975
Gain on extinguishment of debt	0	(150,802)
Impairment of long-lived assets	9,883	15,447
(Gain) loss on derivatives	(49,942)	26,269
Equity in (income) loss of equity method investees	(12)	14
Unit-based compensation	2,827	4,003
(Gain) loss on disposal of assets	5,525	(40,842)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	1,003	(1,634)
(Increase) decrease in accounts receivable, joint interest owners	(3,259)	11,626
(Increase) decrease in accounts receivable, other	(399)	84
(Increase) decrease in other assets	160	(2,452)
Decrease in accounts payable	(109)	(9,859)
Increase in accrued oil and natural gas liabilities	8,519	4,513
Decrease in other liabilities	(4,558)	(5,663)
Total adjustments	29,836	(67,694)
Net cash provided by (used in) operating activities	35,131	(14,626)
Cash flows from investing activities:
Investment in oil and natural gas properties	(61,910)	(14,103)
(Costs) proceeds associated with sale of assets	(199)	87,475
Investment in other equipment	(110)	(312)
Net cash settlements received on commodity derivatives	10,807	44,871
Net cash (used in) provided by investing activities	(51,412)	117,931
Cash flows from financing activities:
Proceeds from long-term debt	211,000	81,000
Payments of long-term debt	(196,000)	(181,402)
Payments of debt issuance costs	(60)	(3,769)
Net cash provided by (used in) financing activities	14,940	(104,171)
Net decrease in cash and cash equivalents	(1,341)	(866)
Cash, beginning of period	2,555	2,006
Cash, end of period	1,214	1,140
Non-cash investing and financing activities:
Asset retirement obligations associated with properties sold	(5,650)	(21,664)
Note receivable received in exchange for sale of oil and natural gas properties	748	0
Units issued in exchange for outstanding Senior Notes	$ 0	$ (6,607)

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2017
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 consolidated 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, 2017 and for the three and six months ended June 30, 2017 and 2016 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, 2016 . LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and owns an approximate 0.03% general partner interest in LRLP. Significant information regarding rights of unitholders includes the following: • Right to receive, within 45 days after the end of each quarter, distributions of available cash, if distributions are declared. • No limited partner shall have any management power over LRLP’s business and affairs; the general partner shall conduct, direct and manage LRLP’s activities. • The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRGPLLC and its affiliates, provided that a unit majority has elected a successor general partner. • Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year. In the event of liquidation, after making required payments to Legacy's preferred unitholders, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRGPLLC in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation. Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin (West Texas and Southeast New Mexico), East Texas, Rocky Mountain and Mid-Continent regions of the United States. (b) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of June 30, 2017 and December 31, 2016 : June 30, December 31, (In thousands) Revenue payable to joint interest owners $ 23,485 $ 19,576 Accrued lease operating expense 14,564 17,696 Accrued capital expenditures 12,471 7,019 Accrued ad valorem tax 7,502 5,300 Other 3,745 3,657 $ 61,767 $ 53,248 (c) Restricted Cash Restricted cash on our Balance Sheet as of June 30, 2017 and December 31, 2016 is recorded as $3.2 million and $3.6 million , respectively, in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. (d) Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on Legacy's results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the consolidated financial statements, with certain practical expedients available. Legacy is currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Legacy is currently determining the impacts of the new standard on its contract portfolio. Legacy's approach includes performing a detailed review of key contracts representative of Legacy's business and comparing historical accounting policies and practices to the new standard. Legacy's contracts are primarily short-term in nature, and its assessment at this stage is that, other than additional disclosures, Legacy does not expect the new revenue recognition standard will have a material impact on its consolidated financial statements upon adoption.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following as of June 30, 2017 and December 31, 2016 : June 30, December 31, 2017 2016 (In thousands) Credit Facility due 2019 $ 478,000 $ 463,000 Second Lien Term Loans due 2020 60,000 60,000 8% Senior Notes due 2020 232,989 232,989 6.625% Senior Notes due 2021 432,656 432,656 1,203,645 1,188,645 Unamortized discount on Second Lien Term Loans and Senior Notes (11,579 ) (12,802 ) Unamortized debt issuance costs (12,019 ) (14,449 ) Total Long-Term Debt $ 1,180,047 $ 1,161,394 Credit Facility On April 1, 2014, Legacy entered into a five -year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents and the lenders party thereto (the “Current Credit Agreement”). Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 95% 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 reaffirmed at $600 million on March 30, 2017. The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year with the next redetermination scheduled for October 2017. 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. The Current Credit Agreement contains a covenant that prohibits Legacy from paying distributions to its limited partners, including holders of its preferred units, if Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than 4.00 to 1.00. The Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows: • first lien debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to not be greater than: (i) 3.00 to 1.00, at any time during the fiscal quarter ending June 30, 2017 and (ii) 2.50 to 1.00, at any time on or after July 1, 2017; • secured debt to EBITDA as of the last day of any fiscal quarter for the four fiscal quarters then ending of not more than 4.5 to 1.0, beginning with the fiscal quarter ending on December 31, 2018; • 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 2.0 to 1.0; • 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; and • the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at 10 percent per annum, of Legacy’s proved developed producing oil and gas properties (“PDP PV-10”) as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents, in each case as of such date to (b) Secured Debt as of such day to be equal to or less than 1.00 to 1.00 beginning with the fiscal quarter ending June 30, 2017. All capitalized terms not defined in the foregoing description have the meaning assigned to them in the Current Credit Agreement Amendment. As of June 30, 2017 , Legacy was in compliance with all financial and other covenants of the Current Credit Agreement. Depending on future oil and natural gas prices, Legacy could breach certain financial covenants under its revolving credit facility, which would constitute a default under its revolving credit facility. Such default, if not remedied, would require a waiver from Legacy's lenders in order for it to avoid an event of default and, subject to certain limitations, subsequent acceleration of all amounts outstanding under its revolving credit facility and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's revolving credit facility were to accelerate the indebtedness under its revolving credit facility as a result of a default, such acceleration could cause a cross-default of all of its other outstanding indebtedness, including its Second Lien Term Loans, its 8% Senior Notes due 2020 (the "2020 Senior Notes") and its 6.625% Senior Notes due 2021 (the "2021 Senior Notes" and, together with the 2020 Senior Notes, the “Senior Notes”), and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, Legacy believes the long-term global outlook for commodity prices and its efforts to date will be viewed positively by its lenders. The Current Credit Agreement contains a covenant that currently prohibits us from paying distributions to our limited partners, including holders of our preferred units. As of June 30, 2017 , Legacy had approximately $478.0 million drawn under the Current Credit Agreement at a weighted-average interest rate of 3.80% , leaving approximately $120.1 million of availability under the Current Credit Agreement. For the six -month period ended June 30, 2017 , Legacy paid in cash $9.5 million of interest expense on the Current Credit Agreement. Second Lien Term Loan Credit Agreement On October 25, 2016, Legacy entered into a Term Loan Credit Agreement (the “Second Lien Term Loan Credit Agreement”) among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, providing for term loans up to an aggregate principal amount of $300.0 million (the “Second Lien Term Loans”). GSO Capital Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Second Lien Term Loans mature on August 31, 2020. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Current Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Current Credit Agreement. As of June 30, 2017 , Legacy had approximately $60.0 million drawn under the Second Lien Term Loan Credit Agreement. On August 1, 2017 Legacy drew an additional $145.0 million under the Second Lien Term Loan Credit Agreement in order to fund certain payments in connection with the amendment and restatement of Legacy's Development Agreement with Jupiter JV LP. For more information, please read “—Footnote 10—Subsequent Events."The remaining $95.0 million of availability as of August 1, 2017 under the Second Lien Term Loan Credit Agreement is available until October 25, 2017. The Second Lien Term Loan Credit Agreement contains a covenant that prohibits Legacy from paying distributions to its limited partners, including holders of its preferred units, if Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than 4.00 to 1.00. The Second Lien Term Loan Credit Agreement also contains covenants that, among other things, require us to: • not permit, beginning with the fiscal quarter ending June 30, 2017, the ratio of the sum of (i) the net present value using NYMEX forward pricing of Legacy’s PDP PV-10, (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than 1.0 to 1.0; and • not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than 4.50 to 1.00. All capitalized terms used but not defined in the foregoing description have the meaning assigned to them in the Second Lien Term Loan Credit Agreement. In connection with the Second Lien Term Loan Credit Agreement, a customary intercreditor agreement was entered into by Wells Fargo Bank National Association, as priority lien agent, and Cortland Capital Markets Services LLC, as junior lien agent, and acknowledged and accepted by Legacy and the subsidiary guarantors. As of June 30, 2017 , Legacy was in compliance with all financial and other covenants of the Second Lien Term Loan Credit Agreement. 8% Senior Notes Due 2020 On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of its 2020 Senior Notes, which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at any time 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 may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy's and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other, debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to "—Footnote 9—Subsidiary Guarantors" for further details on Legacy's guarantors. The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the 2020 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2020 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. Interest is payable on June 1 and December 1 of each year. During the fiscal year ended December 31, 2016, Legacy repurchased a face amount of $52.0 million of its 2020 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. On June 1, 2016, Legacy exchanged 2,719,124 units representing limited partner interests in the Partnership for $15.0 million of face amount of its outstanding 2020 Senior Notes. Legacy treated this exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on June 1, 2016. 6.625% Senior Notes Due 2021 On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of its 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 6.625% 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on February 10, 2015. These 2021 Senior Notes were issued at 99.0% of par. The terms of the 2021 Senior Notes, including details related to Legacy's 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 % Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. The Partnership is in compliance with all financial and other covenants of the 2021 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2021 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. Interest is payable on June 1 and December 1 of each year. During the fiscal year ended December 31, 2016, Legacy repurchased a face amount of $117.3 million of its 2021 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2017
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 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 and retention bonus agreements with its officers and certain other employees. The employment agreements with its officers 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. The retention bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2017
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, 2017 : Fair Value Measurements at June 30, 2017 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, 2017 (In thousands) LTIP (a) $ — $ (557 ) $ — $ (557 ) Oil and natural gas derivatives — 50,446 630 51,076 Interest rate swaps — 940 — 940 Total $ — $ 50,829 $ 630 $ 51,459 (a) See Note 8 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method. Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps, using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published London interbank offered rates ("LIBOR") and interest rate swaps. Due to the lack of an active market for periods beyond one-month from the balance sheet date for its oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that most of our current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: Significant Unobservable Inputs (Level 3) Three Months Ended Six Months Ended 2017 2016 2017 2016 (In thousands) Beginning balance $ 1,666 $ (2,828 ) $ 8 $ (4,493 ) Total gains (losses) (747 ) 888 492 899 Settlements, net (289 ) 650 130 2,304 Ending balance $ 630 $ (1,290 ) $ 630 $ (1,290 ) Gains (losses) included in earnings relating to derivatives still held as of June 30, 2017 and 2016 $ (631 ) $ 581 $ 89 $ 978 During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnership's derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were previously in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within Legacy's consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on Legacy's results of operations or financial condition Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of asset retirement obligations ("ARO") for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 6. Nonrecurring fair value measurements of proved oil and natural gas properties during the six -month period ended June 30, 2017 consist of: Fair Value Measurements During the Six Months Ended June 30, 2017 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) $ — $ — $ 10,899 (a) Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six -month period ended June 30, 2017 , Legacy incurred impairment charges of $9.9 million as oil and natural gas properties with a net cost basis of $20.8 million were written down to their fair value of $10.9 million . In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. The carrying amount of the revolving long-term debt of $478 million as of June 30, 2017 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. The carrying amount of the second lien term loan debt under Legacy’s Second Lien Term Loan Credit Agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. Legacy has classified the Second Lien Term Loans as a Level 2 item within the fair value hierarchy. As of June 30, 2017 , the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $166.2 million and $300.7 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, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Commodity derivative transactions Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes and required no upfront or deferred cash premium paid or payable to our counterparty. All of these price risk management transactions are considered derivative instruments . These derivative instruments are intended to reduce Legacy’s price risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings. By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties, all of whom are current or former members of Legacy's lending group. The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three and six months ended June 30, 2017 and 2016 : Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Beginning fair value of commodity derivatives $ 43,131 $ 112,688 $ 12,698 $ 118,427 Total gain (loss) - oil derivatives 7,776 (5,411 ) 22,776 (2,892 ) Total gain (loss) - natural gas derivatives 6,740 (32,264 ) 26,409 (17,745 ) Crude oil derivative cash settlements received (3,559 ) (9,760 ) (6,698 ) (22,345 ) Natural gas derivative cash settlements received (3,012 ) (12,333 ) (4,109 ) (22,525 ) Ending fair value of commodity derivatives $ 51,076 $ 52,920 $ 51,076 $ 52,920 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, 2017 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 $ 65,471 $ (14,395 ) $ 51,076 Interest rate derivatives 1,114 (80 ) 1,034 Total derivative assets $ 66,585 $ (14,475 ) $ 52,110 Offsetting Derivative Liabilities: Commodity derivatives $ (14,395 ) $ 14,395 $ — Interest rate derivatives (174 ) 80 (94 ) Total derivative liabilities $ (14,569 ) $ 14,475 $ (94 ) December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 56,103 $ (30,648 ) $ 25,455 Interest rate derivatives 1,328 (68 ) 1,260 Total derivative assets $ 57,431 $ (30,716 ) $ 26,715 Offsetting Derivative Liabilities: Commodity derivatives $ (43,405 ) $ 30,648 $ (12,757 ) Interest rate derivatives (1,145 ) 68 (1,077 ) Total derivative liabilities $ (44,550 ) $ 30,716 $ (13,834 ) As of June 30, 2017 , Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2017 92,000 $84.75 $84.75 2018 730,000 $55.04 $55.00 - $55.15 As of June 30, 2017 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2017 1,104,000 $(0.30) $(0.75) $(0.05) 2018 2,190,000 $(1.22) $(1.25) $(1.15) As of June 30, 2017 , Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below: Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl July-December 2017 1,104,000 $45.00 $59.02 2018 1,551,250 $47.06 $60.29 As of June 30, 2017 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below: Average Long Average Short Average Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Swap Price per Bbl July-December 2017 92,000 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of June 30, 2017 , Legacy had the following NYMEX Henry Hub 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 2017 13,800,000 $3.36 $3.29 $3.39 2018 42,200,000 $3.25 $3.04 $3.39 2019 25,800,000 $3.36 $3.29 $3.39 As of June 30, 2017 , Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below: Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu July-December 2017 7,360,000 $2.90 $3.44 As of June 30, 2017 , 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 2017 2,520,000 $3.75 $4.25 $5.53 As of June 30, 2017 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: July-December 2017 Average Volumes (MMBtu) Price per MMBtu NWPL 3,680,000 $(0.16) SoCal 1,260,400 $0.11 San Juan 1,260,400 $(0.10) Interest rate derivative transactions Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged, which has, and could result in overhedged amounts. Legacy accounts for these interest rate swaps at fair value and included in the consolidated balance sheet as assets or liabilities. Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Beginning fair value of interest rate swaps $ 1,025 $ (4,695 ) $ 183 $ (362 ) Total gain (loss) on interest rate swaps (334 ) (1,977 ) 90 (7,049 ) Cash settlements paid 249 678 667 1,417 Ending fair value of interest rate swaps $ 940 $ (5,994 ) $ 940 $ (5,994 ) The table below summarizes the interest rate swap position as of June 30, 2017 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2017 (Dollars in thousands) $ 115,000 0.850 % 9/1/2015 9/1/2017 $ 93 $ 235,000 1.363 % 9/1/2015 9/1/2019 847 Total fair value of interest rate derivatives $ 940

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2017
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, 2017 and year ended December 31, 2016 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 272,148 $ 286,405 Liabilities incurred with properties acquired — 24 Liabilities incurred with properties drilled — 1 Liabilities settled during the period (1,102 ) (2,351 ) Liabilities associated with properties sold (5,650 ) (24,605 ) Current period accretion 6,387 12,674 Asset retirement obligation - end of period $ 271,783 $ 272,148

Partners' Deficit

Partners' Deficit	6 Months Ended
	Jun. 30, 2017
Equity [Abstract]
Partners' Deficit	Partners' Deficit 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" and, together with the Series A Preferred Units, the "Preferred Units") in a public offering at a price of $25.00 per unit. On July 1, 2014, the underwriters exercised their over-allotment option to purchase an additional 200,000 Series B Preferred Units. Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A and 5.26% for Series B, based on the $25.00 liquidation preference per preferred unit. At any time on or after April 15, 2019 or June 15, 2019, Legacy may redeem the Series A Preferred Units or Series B Preferred Units, respectively, in whole or in part at a redemption price of $25.00 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon through and including the date of redemption, whether or not declared. Legacy may also redeem the Preferred Units in the event of a Change of Control. The Series A Preferred Units and the Series B Preferred Units trade on NASDAQ under the symbols "LGCYP" and "LGCYO,” respectively. On January 21, 2016, Legacy announced that its general partner suspended monthly cash distributions for both its Series A Preferred Units and its Series B Preferred Units. As of June 30, 2017 , $2.92 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $27.7 million . Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units") to WPX Energy Rocky Mountain, LLC (“WPX”) as part of Legacy’s purchase of a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX on June 4, 2014 (the “WPX Acquisition”). The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units. Effective January 1, 2016, WPX assigned its vested and unvested IDUs to WPX Energy Holdings, LLC ("WPX Holdings"), a controlled affiliate of WPX Energy, Inc. The Incentive Distribution Units (except for the Unvested IDUs) represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets were set above the levels of Legacy's distributions to unitholders at the time of issuance to WPX. As of June 4, 2017, all of the Unvested IDUs had been forfeited pursuant to their terms of issuance. In addition, the vested and outstanding Incentive Distribution Units held by WPX Holdings may be converted by Legacy, subject to applicable conversion factors, into units on a one -for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus for such quarter. Further, WPX Holdings also has the ability to similarly convert any of its vested Incentive Distribution Units beginning three years after June 4, 2014. WPX Holdings may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX Energy, Inc. Income (loss) per unit The following table sets forth the computation of basic and diluted income (loss) per unit: Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 (In thousands) Net income (loss) $ (11,077 ) $ (52,261 ) $ 5,295 $ 53,068 Distributions to preferred unitholders (4,750 ) (4,750 ) (9,500 ) (8,708 ) Net income (loss) attributable to unitholders $ (15,827 ) $ (57,011 ) (4,205 ) 44,360 Weighted average number of units outstanding 72,354 70,071 72,229 69,518 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 72,354 70,071 72,229 69,518 Basic and diluted income per unit $ (0.22 ) $ (0.81 ) $ (0.06 ) $ 0.64 For the three and six months ended June 30, 2017 , 324,604 restricted units and 1,389,773 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, 2016 , 431,691 restricted units and 1,212,692 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect.

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2017
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, 2017 , grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 3,388,947 units had been made, comprised of 266,014 unit option awards, 1,012,394 restricted unit awards, 1,389,773 phantom unit awards and 720,766 unit awards. The UAR awards and certain phantom unit awards granted under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of LRGPLLC. The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Because the UARs are settled in cash, Legacy accounts for them by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods. Unit Appreciation Rights A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method. Legacy did not issue UARs to employees during the year ended December 31, 2016 or the six -month period ended June 30, 2017 . For the six -month periods ended June 30, 2017 and 2016 , Legacy recorded $(86,290) and $112,100 , respectively, of compensation (benefit) expense due to the change in liability from December 31, 2016 and 2015 , respectively, based on its use of the Black-Scholes model to estimate the June 30, 2017 and 2016 fair value of these UARs (see Note 4). As of June 30, 2017 , there was a total of approximately $49,339 of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At June 30, 2017 , this cost was expected to be recognized over a weighted-average period of approximately 1.15 years. Compensation expense is based upon the fair value as of June 30, 2017 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 85% and employed the Black-Scholes model to estimate the June 30, 2017 fair value to be realized as compensation cost based on the percentage of service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 5.4% . Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed no annual distribution. A summary of UAR activity for the six months ended June 30, 2017 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2017 884,546 $ 20.75 3.68 $ — Expired and forfeited (95,108 ) 23.90 Outstanding at June 30, 2017 789,438 $ 20.37 3.52 $ — UARs exercisable at June 30, 2017 501,263 $ 24.22 2.75 $ — The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2017 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2017 314,177 $ 14.16 Vested (14,668 ) 20.00 Forfeited (9,667 ) 17.31 Non-vested at June 30, 2017 289,842 $ 13.67 Legacy has used a weighted-average risk-free interest rate of 1.7% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at June 30, 2017 whose terms are consistent with the expected life of the UARs. Expected life represents the period of time that UARs are expected to be outstanding and is based on Legacy’s best estimate. The following table represents the weighted-average assumptions used for the Black-Scholes option-pricing model. Six Months Ended June 30, Expected life (years) 3.52 Risk free interest rate 1.7 % Annual distribution rate per unit $0.00 Volatility 85.5 % Phantom Units Legacy has also issued phantom units under the LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy is accounting for the phantom units settled in Partnership units by utilizing the equity method. Legacy is accounting for the phantom units settled in cash by utilizing the liability method. On June 22, 2016 , the Compensation Committee approved with respect to Paul Horne, and the board of directors of LRGPLLC approved the recommendation of the Compensation Committee with respect to the other executive officers the award of a maximum of 391,674 subjective, or service-based, phantom units that, upon vesting, settle in Partnership units, a maximum of 1,286,930 subjective phantom units that, upon vesting, settle in cash and a maximum of 2,238,138 objective, or performance-based, phantom units that, upon vesting, settle in cash to our executive officers. On February 21, 2017 , the Compensation Committee approved the award to Legacy's executive officers of a maximum of 396,850 subjective, or service-based, phantom units that, upon vesting, settle in units, a maximum of 793,701 subjective phantom units that, upon vesting, settle in cash and a maximum of 1,587,402 objective, or performance-based, phantom units that, upon vesting, settle in cash. Compensation expense related to the phantom units was $1.9 million and $1.8 million for the six months ended June 30, 2017 and 2016 , respectively. Restricted Units During the year ended December 31, 2016 , Legacy issued an aggregate of 137,569 restricted units to non-executive employees. The restricted units vest ratably over a three -year period beginning at the date of grant. During the six -month period ended June 30, 2017 , Legacy did not issue restricted units to any employees. Compensation expense related to restricted units was $1.0 million and $1.6 million for the six months ended June 30, 2017 and 2016 , respectively. As of June 30, 2017 , there was a total of $1.4 million of unrecognized compensation expense related to the unvested portion of these restricted units. At June 30, 2017 , this cost was expected to be recognized over a weighted-average period of 1.7 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at June 30, 2017 , do not include 324,604 units related to unvested restricted unit awards. Board Units On May 10, 2016, Legacy granted and issued 39,526 units to each of its non-employee directors. The value of each unit was $2.59 at the time of issuance. On May 16, 2017, Legacy granted and issued 47,847 units to each of the six non-employee directors who receive compensation for their service on Legacy's board of directors. The value of each unit was $2.04 at the time of issuance.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2017
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by Legacy's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in “—Footnote 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, 2017
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On August 1, 2017, Legacy, along with Jupiter JV LP (“Investor”), entered into the First Amended and Restated Development Agreement (the “Restated Agreement”), which amends and restates the Development Agreement, dated July 2, 2015, between Legacy and Investor (the “Original Development Agreement”) pursuant to which Legacy and Investor agreed to participate in the funding, exploration, development and operation of certain of Legacy’s undeveloped oil and gas properties in the Permian Basin. Under the Restated Agreement, the parties have committed to develop a tranche of 16 wells (the "Second Tranche"), and Legacy must propose an additional tranche of 10 wells in which Investor can elect to participate (the “Third Tranche”). Investor may elect to combine the drilling of the wells to be included in the Third Tranche into the Second Tranche. Investor’s share of its portion of development costs will be limited to $40 million for the Second Tranche, and, if Investor elects to participate in the Third Tranche, its portion of development costs will be limited to $50 million for those wells. In accordance with the Restated Agreement, Legacy made a payment of $141 million (the “Acceleration Payment”) to cause the reversion of Investor's working interest from 80% to 15% of the parties' combined interests in all wells contained in the first tranche such that Legacy's working interest reverted from 20% to 85% of the parties' combined working interests in all wells contained in the tranche, and all undeveloped assets subject to the terms of the Restated Agreement reverted back to Legacy. Legacy will account for the reversion of interests as a result of the Acceleration Payment as a business combination of incremental working interest in all wells contained in the First Tranche. Pursuant to the Restated Agreement, Investor shall fund 40% of the costs to the parties' combined interests to develop the wells in the Second Tranche of 16 wells in exchange for an undivided 33.7% working interest of Legacy’s original working interest in the wells, subject to a reversionary interest of 6.3% of Legacy’s original working interest in the wells upon the occurrence of Investor achieving a 15% internal rate of return in the aggregate with respect to such tranche of wells. Investor will have the option to fund the Third Tranche on identical terms and will also have the opportunity to participate in a maximum of 6 additional wells per tranche in the Restated Agreement’s area of mutual interest. The Restated Agreement provides that Investor can suspend its obligation to fund wells in a tranche upon the occurrence of certain events, but that Legacy can continue to drill and fund on its own any such wells in which Investor elects to not participate (subject to Investor's later right to participate in such wells in accordance with the Restated Agreement). Additionally, the management fee to be paid to Legacy under the Management Services Agreement entered into at the time of the execution of the Original Development Agreement has been proportionately reduced to reflect Investor’s decreased working interest in the properties. The Acceleration Payment was funded by a $145 million draw under the Second Lien Term Loan Credit Agreement. In connection with the draw under the Second Lien Term Loan Credit Agreement, the lenders of Legacy's Current Credit Agreement affirmed Legacy's borrowing base at $600 million . In connection with the execution of the Restated Agreement, GSO, as lender under our Second Lien Term Loan Credit Agreement, has provided a waiver to Legacy to make capital expenditures that are expected to be required to develop the assets under the Restated Agreement.

Summary of Significant Accoun17

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2017
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, 2017 and for the three and six months ended June 30, 2017 and 2016 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, 2016 .
Restricted Cash	Restricted Cash Restricted cash on our Balance Sheet as of June 30, 2017 and December 31, 2016 is recorded as $3.2 million and $3.6 million , respectively, in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of busines
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on Legacy's results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the consolidated financial statements, with certain practical expedients available. Legacy is currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Legacy is currently determining the impacts of the new standard on its contract portfolio. Legacy's approach includes performing a detailed review of key contracts representative of Legacy's business and comparing historical accounting policies and practices to the new standard. Legacy's contracts are primarily short-term in nature, and its assessment at this stage is that, other than additional disclosures, Legacy does not expect the new revenue recognition standard will have a material impact on its consolidated financial statements upon adoption.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2017
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, 2017 and December 31, 2016 : June 30, December 31, (In thousands) Revenue payable to joint interest owners $ 23,485 $ 19,576 Accrued lease operating expense 14,564 17,696 Accrued capital expenditures 12,471 7,019 Accrued ad valorem tax 7,502 5,300 Other 3,745 3,657 $ 61,767 $ 53,248

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following as of June 30, 2017 and December 31, 2016 : June 30, December 31, 2017 2016 (In thousands) Credit Facility due 2019 $ 478,000 $ 463,000 Second Lien Term Loans due 2020 60,000 60,000 8% Senior Notes due 2020 232,989 232,989 6.625% Senior Notes due 2021 432,656 432,656 1,203,645 1,188,645 Unamortized discount on Second Lien Term Loans and Senior Notes (11,579 ) (12,802 ) Unamortized debt issuance costs (12,019 ) (14,449 ) Total Long-Term Debt $ 1,180,047 $ 1,161,394
Schedule of debt redemption	Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at any time at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. Year Percentage 2016 104.000 % 2017 102.000 % 2018 and thereafter 100.000 % The terms of the 2021 Senior Notes, including details related to Legacy's 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 %

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2017
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, 2017 : Fair Value Measurements at June 30, 2017 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, 2017 (In thousands) LTIP (a) $ — $ (557 ) $ — $ (557 ) Oil and natural gas derivatives — 50,446 630 51,076 Interest rate swaps — 940 — 940 Total $ — $ 50,829 $ 630 $ 51,459 (a) See Note 8 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 2017 2016 2017 2016 (In thousands) Beginning balance $ 1,666 $ (2,828 ) $ 8 $ (4,493 ) Total gains (losses) (747 ) 888 492 899 Settlements, net (289 ) 650 130 2,304 Ending balance $ 630 $ (1,290 ) $ 630 $ (1,290 ) Gains (losses) included in earnings relating to derivatives still held as of June 30, 2017 and 2016 $ (631 ) $ 581 $ 89 $ 978
Schedule of fair value measurements of proved oil and natural gas properties	Nonrecurring fair value measurements of proved oil and natural gas properties during the six -month period ended June 30, 2017 consist of: Fair Value Measurements During the Six Months Ended June 30, 2017 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) $ — $ — $ 10,899 (a) Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six -month period ended June 30, 2017 , Legacy incurred impairment charges of $9.9 million as oil and natural gas properties with a net cost basis of $20.8 million were written down to their fair value of $10.9 million . In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Derivative Financial Instrume21

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2017
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, 2017 and 2016 : Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Beginning fair value of commodity derivatives $ 43,131 $ 112,688 $ 12,698 $ 118,427 Total gain (loss) - oil derivatives 7,776 (5,411 ) 22,776 (2,892 ) Total gain (loss) - natural gas derivatives 6,740 (32,264 ) 26,409 (17,745 ) Crude oil derivative cash settlements received (3,559 ) (9,760 ) (6,698 ) (22,345 ) Natural gas derivative cash settlements received (3,012 ) (12,333 ) (4,109 ) (22,525 ) Ending fair value of commodity derivatives $ 51,076 $ 52,920 $ 51,076 $ 52,920
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, 2017 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 $ 65,471 $ (14,395 ) $ 51,076 Interest rate derivatives 1,114 (80 ) 1,034 Total derivative assets $ 66,585 $ (14,475 ) $ 52,110 Offsetting Derivative Liabilities: Commodity derivatives $ (14,395 ) $ 14,395 $ — Interest rate derivatives (174 ) 80 (94 ) Total derivative liabilities $ (14,569 ) $ 14,475 $ (94 ) December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 56,103 $ (30,648 ) $ 25,455 Interest rate derivatives 1,328 (68 ) 1,260 Total derivative assets $ 57,431 $ (30,716 ) $ 26,715 Offsetting Derivative Liabilities: Commodity derivatives $ (43,405 ) $ 30,648 $ (12,757 ) Interest rate derivatives (1,145 ) 68 (1,077 ) Total derivative liabilities $ (44,550 ) $ 30,716 $ (13,834 )
Schedule of notional amounts of outstanding derivative positions	As of June 30, 2017 , Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2017 92,000 $84.75 $84.75 2018 730,000 $55.04 $55.00 - $55.15 As of June 30, 2017 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2017 1,104,000 $(0.30) $(0.75) $(0.05) 2018 2,190,000 $(1.22) $(1.25) $(1.15) As of June 30, 2017 , Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below: Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl July-December 2017 1,104,000 $45.00 $59.02 2018 1,551,250 $47.06 $60.29 As of June 30, 2017 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below: Average Long Average Short Average Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Swap Price per Bbl July-December 2017 92,000 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of June 30, 2017 , Legacy had the following NYMEX Henry Hub 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 2017 13,800,000 $3.36 $3.29 $3.39 2018 42,200,000 $3.25 $3.04 $3.39 2019 25,800,000 $3.36 $3.29 $3.39 As of June 30, 2017 , Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below: Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu July-December 2017 7,360,000 $2.90 $3.44 As of June 30, 2017 , 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 2017 2,520,000 $3.75 $4.25 $5.53 As of June 30, 2017 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: July-December 2017 Average Volumes (MMBtu) Price per MMBtu NWPL 3,680,000 $(0.16) SoCal 1,260,400 $0.11 San Juan 1,260,400 $(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 June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Beginning fair value of interest rate swaps $ 1,025 $ (4,695 ) $ 183 $ (362 ) Total gain (loss) on interest rate swaps (334 ) (1,977 ) 90 (7,049 ) Cash settlements paid 249 678 667 1,417 Ending fair value of interest rate swaps $ 940 $ (5,994 ) $ 940 $ (5,994 )
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap position as of June 30, 2017 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2017 (Dollars in thousands) $ 115,000 0.850 % 9/1/2015 9/1/2017 $ 93 $ 235,000 1.363 % 9/1/2015 9/1/2019 847 Total fair value of interest rate derivatives $ 940

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2017
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, 2017 and year ended December 31, 2016 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 272,148 $ 286,405 Liabilities incurred with properties acquired — 24 Liabilities incurred with properties drilled — 1 Liabilities settled during the period (1,102 ) (2,351 ) Liabilities associated with properties sold (5,650 ) (24,605 ) Current period accretion 6,387 12,674 Asset retirement obligation - end of period $ 271,783 $ 272,148

Partners' Deficit (Tables)

Partners' Deficit (Tables)	6 Months Ended
	Jun. 30, 2017
Equity [Abstract]
Schedule of computation of basic and diluted income (loss) per unit	The following table sets forth the computation of basic and diluted income (loss) per unit: Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 (In thousands) Net income (loss) $ (11,077 ) $ (52,261 ) $ 5,295 $ 53,068 Distributions to preferred unitholders (4,750 ) (4,750 ) (9,500 ) (8,708 ) Net income (loss) attributable to unitholders $ (15,827 ) $ (57,011 ) (4,205 ) 44,360 Weighted average number of units outstanding 72,354 70,071 72,229 69,518 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 72,354 70,071 72,229 69,518 Basic and diluted income per unit $ (0.22 ) $ (0.81 ) $ (0.06 ) $ 0.64

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of option and UAR activity	A summary of UAR activity for the six months ended June 30, 2017 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2017 884,546 $ 20.75 3.68 $ — Expired and forfeited (95,108 ) 23.90 Outstanding at June 30, 2017 789,438 $ 20.37 3.52 $ — UARs exercisable at June 30, 2017 501,263 $ 24.22 2.75 $ —
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, 2017 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2017 314,177 $ 14.16 Vested (14,668 ) 20.00 Forfeited (9,667 ) 17.31 Non-vested at June 30, 2017 289,842 $ 13.67
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) 3.52 Risk free interest rate 1.7 % Annual distribution rate per unit $0.00 Volatility 85.5 %

Summary of Significant Accoun25

Summary of Significant Accounting Policies - Other Narrative (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General partner's equity, percent	0.03%	0.03%
Term of right to receive distributions of available cash after quarter end	45 days
Minimum percentage of unitholder approval to remove general partner	66.67%
Term of right to receive information reasonably required for tax reporting purposes after close of year	90 days

Summary of Significant Accoun26

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue payable to joint interest owners	$ 23,485	$ 19,576
Accrued lease operating expense	14,564	17,696
Accrued capital expenditures	12,471	7,019
Accrued ad valorem tax	7,502	5,300
Other	3,745	3,657
Accrued oil and natural gas liabilities	$ 61,767	$ 53,248

Summary of Significant Accoun27

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted Cash	$ 3.2	$ 3.6

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	May 13, 2014
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,203,645	$ 1,188,645
Unamortized discount on Second Lien Term Loans and Senior Notes	(11,579)	(12,802)
Unamortized debt issuance costs	(12,019)	(14,449)
Total Long-Term Debt	1,180,047	1,161,394
Second Lien Term Loan Due in 2020
Debt Instrument [Line Items]
Long-term debt, gross	$ 60,000	60,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate	8.00%
Long-term debt, gross	$ 232,989	232,989
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Stated interest rate	6.625%		6.625%
Long-term debt, gross	$ 432,656	432,656
Credit facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 478,000	$ 463,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility (Details)	Apr. 01, 2014USD ($)	Jun. 30, 2017USD ($)	Oct. 01, 2018	Jul. 01, 2017	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	May 13, 2014
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 1,203,645,000				$ 1,188,645,000
Credit facility due 2019
Line of Credit Facility [Line Items]
Expiration period	5 years
Maximum borrowing capacity	$ 1,500,000,000
Minimum percent of total property value securing credit agreement	95.00%
Borrowing base					$ 600,000,000
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	66.67%
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization required for distributions, maximum		4
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum		3
Ratio of EBITDA to interest expense, minimum		2
Ratio of current assets to current liabilities, minimum		1
Net present value of proved oil and gas properties, discount rate		10.00%
Minimum required cash and cash equivalents to secured debt ratio		1
Long-term debt, gross		$ 478,000,000				463,000,000
Interest rate at period end		3.80%
Remaining borrowing capacity		$ 120,100,000
Interest paid		$ 9,500,000
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000
Senior notes | 8% Senior Notes due 2020
Line of Credit Facility [Line Items]
Stated interest rate		8.00%
Long-term debt, gross		$ 232,989,000				232,989,000
Senior notes | 6.625% Senior Notes due 2021
Line of Credit Facility [Line Items]
Stated interest rate		6.625%					6.625%
Long-term debt, gross		$ 432,656,000				$ 432,656,000
Scenario, Forecast | Credit facility due 2019
Line of Credit Facility [Line Items]
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum			4.5	2.50

Long-Term Debt - Second Lien Te

Long-Term Debt - Second Lien Term Loans (Details)	Aug. 01, 2017USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Oct. 01, 2018	Dec. 31, 2016USD ($)	Oct. 25, 2016USD ($)
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,203,645,000			$ 1,188,645,000
Proceeds from long-term debt		211,000,000	$ 81,000,000
Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Aggregate principal amount						$ 300,000,000
Long-term debt, gross		$ 60,000,000
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization required for distributions, maximum		4
Minimum required cash and cash equivalents to secured debt ratio		1
Scenario, Forecast | Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Ratio of secured debt to EBITDA				4.5
Subsequent Event | Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Proceeds from long-term debt	$ 145,000,000
Unused borrowing capacity	$ 95,000,000

Long-Term Debt - Senior Notes (

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

Commitments and Contingencies (

Commitments and Contingencies (Details) - Officer	6 Months Ended
	Jun. 30, 2017
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, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	$ 1,173,542		$ 1,173,542		$ 1,181,909
Impairment of long-lived assets			9,900
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	166,200		166,200
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	300,700		300,700
Recurring
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP	(557)		(557)
Total	51,459		51,459
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 assets	51,076		51,076
Recurring | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets	940		940
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	0		0
Total	0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets	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 assets	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	(557)		(557)
Total	50,829		50,829
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 assets	50,446		50,446
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 assets	940		940
Recurring | Significant Unobservable Inputs (Level 3)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP	0		0
Total	630		630
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance	1,666	$ (2,828)	8	$ (4,493)
Total gains (losses)	(747)	888	492	899
Settlements, net	(289)	650	130	2,304
Ending balance	630	(1,290)	630	(1,290)
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Gains (losses) included in earnings relating to derivatives still held	(631)	$ 581	89	$ 978
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 assets	630		630
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 assets	0		0
Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	0		0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	0		0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	10,899		10,899
Oil and gas properties, cost basis	20,800		20,800
Revolving Credit Facility
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Revolving long-term debt	$ 478,000		$ 478,000

Derivative Financial Instrume34

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives			$ 49,942	$ (26,269)
Derivative cash settlements paid (received)			(10,807)	(44,871)
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	$ 43,131	$ 112,688	12,698	118,427
Ending fair value of derivatives	51,076	52,920	51,076	52,920
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	7,776	(5,411)	22,776	(2,892)
Derivative cash settlements paid (received)	(3,559)	(9,760)	(6,698)	(22,345)
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	6,740	(32,264)	26,409	(17,745)
Derivative cash settlements paid (received)	$ (3,012)	$ (12,333)	$ (4,109)	$ (22,525)

Derivative Financial Instrume35

Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	$ 66,585	$ 57,431
Gross Amounts Offset in the Consolidated Balance Sheets	(14,475)	(30,716)
Net Amounts Presented in the Consolidated Balance Sheets	52,110	26,715
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(14,569)	(44,550)
Gross Amounts Offset in the Consolidated Balance Sheets	14,475	30,716
Net Amounts Presented in the Consolidated Balance Sheets	(94)	(13,834)
Commodity contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	65,471	56,103
Gross Amounts Offset in the Consolidated Balance Sheets	(14,395)	(30,648)
Net Amounts Presented in the Consolidated Balance Sheets	51,076	25,455
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(14,395)	(43,405)
Gross Amounts Offset in the Consolidated Balance Sheets	14,395	30,648
Net Amounts Presented in the Consolidated Balance Sheets	0	(12,757)
Interest rate contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	1,114	1,328
Gross Amounts Offset in the Consolidated Balance Sheets	(80)	(68)
Net Amounts Presented in the Consolidated Balance Sheets	1,034	1,260
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(174)	(1,145)
Gross Amounts Offset in the Consolidated Balance Sheets	80	68
Net Amounts Presented in the Consolidated Balance Sheets	$ (94)	$ (1,077)

Derivative Financial Instrume36

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details) $ in Thousands	Jun. 30, 2017USD ($)MMBTUbbl$ / MMBTU$ / bbl
NYMEX WTI Swaps | Crude Oil | July-December 2017
Derivative [Line Items]
Volumes | bbl	92,000
Average Price per Bbl/MMBtu	84.75
Price Range	84.75
NYMEX WTI Swaps | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	730,000
Average Price per Bbl/MMBtu	55.04
NYMEX WTI Swaps | Crude Oil | 2018 | Minimum
Derivative [Line Items]
Price Range	55
NYMEX WTI Swaps | Crude Oil | 2018 | Maximum
Derivative [Line Items]
Price Range	55.15
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2017
Derivative [Line Items]
Volumes | bbl	1,104,000
Average Price per Bbl/MMBtu	0.30
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2017 | Minimum
Derivative [Line Items]
Price Range	0.75
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2017 | Maximum
Derivative [Line Items]
Price Range	0.05
Midland-to-Cushing Differential Swaps | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	2,190,000
Average Price per Bbl/MMBtu	1.22
Midland-to-Cushing Differential Swaps | Crude Oil | 2018 | Minimum
Derivative [Line Items]
Price Range	1.25
Midland-to-Cushing Differential Swaps | Crude Oil | 2018 | Maximum
Derivative [Line Items]
Price Range	1.15
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Crude Oil | July-December 2017
Derivative [Line Items]
Volumes | bbl	1,104,000
Average Long Put Price for Crude Oil Collar	45
Average Short Call Price for Crude Oil Collar	59.02
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	1,551,250
Average Long Put Price for Crude Oil Collar	47.06
Average Short Call Price for Crude Oil Collar	60.29
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2017
Derivative [Line Items]
Volumes | bbl	92,000
Average Price per Bbl/MMBtu	90.85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2017 | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2017 | 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 per Bbl/MMBtu	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX Henry Hub, Waha Swaps | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	13,800,000
Average Price per Bbl/MMBtu | $ / MMBTU	3.36
NYMEX Henry Hub, Waha Swaps | Natural gas | July-December 2017 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.29
NYMEX Henry Hub, Waha Swaps | Natural gas | July-December 2017 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	3.39
NYMEX Henry Hub, Waha Swaps | Natural gas | 2018
Derivative [Line Items]
Volumes | MMBTU	42,200,000
Average Price per Bbl/MMBtu | $ / MMBTU	3.25
NYMEX Henry Hub, Waha Swaps | Natural gas | 2018 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.04
NYMEX Henry Hub, Waha Swaps | Natural gas | 2018 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	3.39
NYMEX Henry Hub, Waha Swaps | Natural gas | 2019
Derivative [Line Items]
Volumes | MMBTU	25,800,000
Average Price per Bbl/MMBtu | $ / MMBTU	3.36
NYMEX Henry Hub, Waha Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	3.29
NYMEX Henry Hub, Waha Swaps | Natural gas | 2019 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	3.39
NYMEX Henry Hub, Waha Collar | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	7,360,000
Average Long Put Price for Natural Gas Collar | $ / MMBTU	2.90
Average Short Call Price for Natural Gas Collar | $ / MMBTU	3.44
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	2,520,000
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	3,680,000
Average Price per Bbl/MMBtu | $ / MMBTU	0.16
Henry Hub NYMEX to California SoCal NGI Natural Gas Differential Swaps | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	1,260,400
Average Price per Bbl/MMBtu | $ / MMBTU	0.11
Henry Hub NYMEX to San Juan Basin Natural Gas Differential Swaps | Natural gas | July-December 2017
Derivative [Line Items]
Volumes | MMBTU	1,260,400
Average Price per Bbl/MMBtu | $ / MMBTU	0.10
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2017 | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
Call Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.53
Not designated as hedging instrument | Interest rate swaps
Derivative [Line Items]
Estimated Fair Market Value | $	$ 940
Not designated as hedging instrument | Interest Rate Swap Due Sept 2017
Derivative [Line Items]
Notional Amount | $	$ 115,000
Fixed Rate	0.85%
Estimated Fair Market Value | $	$ 93
Not designated as hedging instrument | Interest Rate Swap Due Sept 2019
Derivative [Line Items]
Notional Amount | $	$ 235,000
Fixed Rate	1.363%
Estimated Fair Market Value | $	$ 847

Derivative Financial Instrume37

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Cash settlements paid			$ (10,807)	$ (44,871)
Interest rate swaps | Not designated as hedging instrument
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	$ 1,025	$ (4,695)	183	(362)
Cash settlements paid	249	678	667	1,417
Ending fair value of derivatives	940	(5,994)	940	(5,994)
Interest rate swaps | Not designated as hedging instrument | Interest expense
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on interest rate swaps	$ (334)	$ (1,977)	$ 90	$ (7,049)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Changes in the ARO
Asset retirement obligation - beginning of period	$ 272,148	$ 286,405
Liabilities incurred with properties acquired	0	24
Liabilities incurred with properties drilled	0	1
Liabilities settled during the period	(1,102)	(2,351)
Liabilities associated with properties sold	(5,650)	(24,605)
Current period accretion	6,387	12,674
Asset retirement obligation - end of period	$ 271,783	$ 272,148

Partners' Deficit - Preferred U

Partners' Deficit - Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	Jul. 01, 2014	Jun. 17, 2014	May 12, 2014	Apr. 17, 2014	Jun. 30, 2017	Jun. 15, 2019	Apr. 15, 2019
Class of Stock [Line Items]
Liquidation preference (in dollars per share)					$ 25
Distributions in arrears (in dollars per share)					$ 2.92
Distributions in arrears					$ 27.7
Series A Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)				2,000,000
Dividend rate				8.00%
Share price (in dollars per share)				$ 25
Additional shares of underwriter purchase option (in shares)			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
Dividend rate		8.00%
Share price (in dollars per share)		$ 25
Additional shares of underwriter purchase option (in shares)	200,000
Series B Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate					5.26%
Scenario, Forecast | Series A Preferred Equity
Class of Stock [Line Items]
Redemption price (in dollars per share)							$ 25
Scenario, Forecast | Series B Preferred Equity
Class of Stock [Line Items]
Redemption price (in dollars per share)						$ 25

Partners' Deficit - Incentive D

Partners' Deficit - Incentive Distribution Units (Details) - WPX acquisition	Jun. 04, 2016shares	Jun. 04, 2014$ / sharesshares	Jun. 30, 2017
Class of Stock [Line Items]
Equity interests issuable (in shares)		300,000
IDU conversion ratio			1
Conversion terms, minimum distribution per share (in dollars per share) | $ / shares		$ 0.90
Required period from issue date after which award may be converted		3 years
Unvested IDUs
Class of Stock [Line Items]
Equity interests issuable (in shares)		200,000
Equity interests forfeiture (in shares)	66,666
Immediate vesting
Class of Stock [Line Items]
Equity interests issuable (in shares)		100,000

Partners' Deficit - Income (los

Partners' Deficit - Income (loss) per unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Equity [Abstract]
Net income (loss)	$ (11,077)	$ (52,261)	$ 5,295	$ 53,068
Distributions to preferred unitholders	(4,750)	(4,750)	(9,500)	(8,708)
Net income (loss) attributable to unitholders	$ (15,827)	$ (57,011)	$ (4,205)	$ 44,360
Weighted average number of units outstanding (in shares)	72,354,000	70,071,000	72,229,000	69,518,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	0	0
Weighted average units and potential units outstanding (in shares)	72,354,000	70,071,000	72,229,000	69,518,000
Basic and diluted income per unit (in dollars per share)	$ (0.22)	$ (0.81)	$ (0.06)	$ 0.64
Restricted stock units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)	324,604	431,691	324,604	431,691
Phantom share units (PSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)	1,389,773	1,212,692	1,389,773	1,212,692

Unit-Based Compensation - LTIP,

Unit-Based Compensation - LTIP, Unit Appreciation Rights and Unit Options (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Jun. 12, 2015	Jun. 11, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	1.70%
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	$ 1,000,000	$ 1,600,000
Unrecognized compensation costs	$ 1,400,000
Unrecognized compensation costs, weighted-average remaining period for recognition	1 year 8 months 6 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	$ 1,900,000	1,800,000
Unit appreciation rights (UARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	(86,290)	$ 112,100
Unrecognized compensation costs	$ 49,339
Unrecognized compensation costs, weighted-average remaining period for recognition	1 year 1 month 24 days
Volatility	85.50%
Share based compensation, forfeiture rate	5.40%
Annual distribution	$ 0
Risk free interest rate	1.70%
Unit appreciation rights (UARs) | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units Issued UARs (in shares)	0		0
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)	3,388,947
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)	1,012,394
Long Term Incentive Plan | Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	1,389,773
Long Term Incentive Plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	720,766

Unit-Based Compensation - Optio

Unit-Based Compensation - Option and UAR Activity (Details) - Unit appreciation rights (UARs) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Units (in shares)
Outstanding, beginning balance (in units)	884,546
Expired and forfeited (in units)	(95,108)
Outstanding, ending balance (in units)	789,438	884,546
UARs exercisable (in units)	501,263
Weighted-Average Exercise Price (in dollars per share)
Outstanding, beginning balance (in dollars per unit)	$ 20.75
Expired and forfeited (in dollars per unit)	23.90
Outstanding, ending balance (in dollars per unit)	20.37	$ 20.75
UARs exercisable (in dollars per unit)	$ 24.22
Weighted-Average Remaining Contractual Term
Outstanding	3 years 6 months 7 days	3 years 8 months 4 days
UARs exercisable	2 years 8 months 30 days
Aggregate Intrinsic Value
Outstanding	$ 0	$ 0
UARs exercisable	$ 0

Unit-Based Compensation - Statu

Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details)	6 Months Ended
	Jun. 30, 2017$ / sharesshares
Number of Units
Vested (in units)	0
Unit appreciation rights (UARs)
Number of Units
Non-vested, beginning balance (in units)	314,177
Vested (in units)	(14,668)
Forfeited (in units)	(9,667)
Non-vested, ending balance (in units)	289,842
Weighted- Average Exercise Price
Non-vested, beginning balance (in dollars per unit) | $ / shares	$ 14.16
Vested (in dollars per unit) | $ / shares	20
Forfeited (in dollars per unit) | $ / shares	17.31
Non-vested, ending balance (in dollars per unit) | $ / shares	$ 13.67

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	1.70%
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	3 years 6 months 7 days	3 years 8 months 4 days
Risk free interest rate	1.70%
Annual distribution rate per unit (in dollars per share)	$ 0
Volatility	85.50%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details) $ / shares in Units, $ in Millions	May 16, 2017director$ / sharesshares	Feb. 21, 2017shares	Jun. 22, 2016shares	May 10, 2016$ / sharesshares	Jun. 30, 2017USD ($)shares	Jun. 30, 2016USD ($)	Dec. 31, 2016shares
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Partnership unit conversion ratio					1
Share-based compensation expense | $					$ 1.9	$ 1.8
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)							137,569
Share-based compensation expense | $					1	$ 1.6
Unrecognized compensation costs | $					$ 1.4
Unrecognized compensation costs, period of recognition					1 year 8 months 6 days
Unvested units not included in consolidated balance sheet (in shares)					324,604
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
Unrestricted units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	47,847			39,526
Individuals eligible for plan | director	6
Value of each unit at issuance (in dollars per share) | $ / shares	$ 2.04			$ 2.59
Maximum | Subjective or service based phantom units | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		396,850	391,674
Maximum | Subjective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		793,701	1,286,930
Maximum | Objective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		1,587,402	2,238,138

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - Senior notes	11 Months Ended
	May 08, 2014offering	Jun. 30, 2017	May 13, 2014USD ($)	May 28, 2013USD ($)
Debt Instrument [Line Items]
Number of private offerings | offering	2
Percent of subsidiaries owned		100.00%
6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Aggregate principal amount | $			$ 300,000,000	$ 250,000,000

Subsequent Events (Details)

Subsequent Events (Details)	Aug. 01, 2017USD ($)well	Jul. 31, 2017	Mar. 31, 2017USD ($)
Permian Basin, Tranche Two | Subsequent Event
Subsequent Event [Line Items]
Maximum number of wells that can be drilled per contractual agreement | well	16
Maximum development costs that the investor may participate in	$ 40,000,000
Permian Basin, Tranche Three | Subsequent Event
Subsequent Event [Line Items]
Maximum number of wells that can be drilled per contractual agreement | well	10
Maximum development costs that the investor may participate in	$ 50,000,000
Permian Basin, Tranche One | Subsequent Event
Subsequent Event [Line Items]
Payments to for development of oil and gas properties	$ 141,000,000
Working interest, investors	15.00%	80.00%
Working interest	85.00%	20.00%
Permian Basin, Tranche Two and Three | Subsequent Event
Subsequent Event [Line Items]
Working interest, investors	33.70%
Contractual obligation, percentage of oil and gas production costs paid for by investors	40.00%
Revisionary interest, investors	6.30%
Minimum rate of return required for investors to acquire revisionary interest	15.00%
Permian Basin, Remaining Tranches | Subsequent Event
Subsequent Event [Line Items]
Maximum number of wells investors can participate in | well	6
Second Lien Term Loan | Subsequent Event
Subsequent Event [Line Items]
Proceeds from second lien term loan	$ 145,000,000
Revolving Credit Facility
Subsequent Event [Line Items]
Borrowing base			$ 600,000,000