Legacy Reserves 10-Q 7 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
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, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		76,929,029

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash	$ 5,948	$ 1,246
Accounts receivable, net:
Oil and natural gas	57,676	62,755
Joint interest owners	16,515	27,420
Other	6	2
Fair value of derivatives (Notes 8 and 9)	28,046	13,424
Prepaid expenses and other current assets (Note 1)	10,457	7,757
Total current assets	118,648	112,604
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,497,220	3,529,971
Unproved properties	31,661	28,023
Accumulated depletion, depreciation, amortization and impairment	(2,157,542)	(2,204,638)
Oil and natural gas properties using the successful efforts method, at cost	1,371,339	1,353,356
Other property and equipment, net of accumulated depreciation and amortization of $11,971 and $11,467, respectively	2,532	2,961
Operating rights, net of amortization of $5,944 and $5,765, respectively	1,072	1,251
Fair value of derivatives (Notes 8 and 9)	9,968	14,099
Other assets	6,991	8,811
Total assets	1,510,550	1,493,082
Current liabilities:
Current debt, net (Notes 1 and 2)	505,222	0
Accounts payable	6,626	13,093
Accrued oil and natural gas liabilities (Note 1)	119,086	81,318
Fair value of derivatives (Notes 8 and 9)	27,740	18,013
Asset retirement obligation (Note 10)	3,214	3,214
Other	46,538	29,172
Total current liabilities	708,426	144,810
Long-term debt, net (Notes 1 and 2)	784,753	1,346,769
Asset retirement obligation (Note 10)	261,031	271,472
Fair value of derivatives (Notes 8 and 9)	6,682	1,075
Other long-term liabilities	643	643
Total liabilities	1,761,535	1,764,769
Commitments and contingencies (Note 7)
Partners' deficit (Note 11):
Limited partners' deficit - 76,793,940 and 72,594,620 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively	(511,095)	(531,794)
General partner's deficit (approximately 0.02%)	(157)	(160)
Total partners' deficit	(250,985)	(271,687)
Total liabilities and partners' deficit	1,510,550	1,493,082
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2018 and December 31, 2017
Partners' deficit (Note 11):
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2018 and December 31, 2017	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2018 and December 31, 2017
Partners' deficit (Note 11):
Preferred equity	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2018 and December 31, 2017
Partners' deficit (Note 11):
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, 2018	Dec. 31, 2017
Other property and equipment, accumulated depreciation and amortization	$ 11,971	$ 11,467
Operating rights, amortization	$ 5,944	$ 5,765
Limited partners' equity, units issued (in shares)	76,793,940	72,594,620
Limited partners' equity, units outstanding (in shares)	76,793,940	72,594,620
General partner's equity, percent	0.02%	0.02%
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, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Total revenues	$ 139,281	$ 92,847	$ 276,760	$ 192,394
Expenses:
Production and other taxes	7,658	4,145	14,984	8,304
General and administrative	22,496	8,581	46,586	19,133
Depletion, depreciation, amortization and accretion	38,139	27,689	74,686	56,485
Impairment of long-lived assets	35,381	1,821	35,381	9,883
(Gains) losses on disposal of assets	(1,145)	11,049	(21,540)	5,525
Total expenses	151,960	98,087	247,495	195,349
Operating (loss) income	(12,679)	(5,240)	29,265	(2,955)
Other income (expense):
Interest income	3	8	15	9
Interest expense (Notes 2, 8 and 9)	(28,589)	(20,614)	(55,957)	(40,747)
Gain on extinguishment of debt (Note 2)	0	0	51,693	0
Equity in income of equity method investees	3	1	20	12
Net gains (losses) on commodity derivatives (Notes 8 and 9)	(9,315)	14,516	(11,019)	49,185
Other	(2)	402	273	362
Income (loss) before income taxes	(50,579)	(10,927)	14,290	5,866
Income tax expense	(130)	(150)	(617)	(571)
Net income (loss)	(50,709)	(11,077)	13,673	5,295
Distributions to preferred unitholders	(4,750)	(4,750)	(9,500)	(9,500)
Net income (loss) attributable to unitholders	$ (55,459)	$ (15,827)	$ 4,173	$ (4,205)
Income (loss) per unit - basic and diluted (in dollars per share)	$ (0.72)	$ (0.22)	$ 0.05	$ (0.06)
Weighted average number of units used in computing net income (loss) per unit -
Basic (in shares)	76,725	72,354	76,539	72,229
Diluted (in shares)	76,725	72,354	77,433	72,229
Oil sales
Revenues:
Total revenues	$ 99,799	$ 46,096	$ 193,210	$ 95,238
Natural gas liquids (NGL) sales
Revenues:
Total revenues	5,735	4,921	13,131	9,971
Natural gas sales
Revenues:
Total revenues	33,747	41,830	70,419	87,185
Oil and gas
Expenses:
Oil and natural gas production	$ 49,431	$ 44,802	$ 97,398	$ 96,019

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Partners' Deficit (Unaudited) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance		$ (271,687)
Unit-based compensation		$ 579
Vesting of restricted and phantom units (in units)		0
Units issued in exchange for Standstill Agreement		$ 5,928
Net income	$ (50,709)	13,673
Unitholders equity, ending balance	$ (250,985)	$ (250,985)
Preferred Equity | Series A Preferred Equity
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		2,300,000
Unitholders equity, beginning balance		$ 55,192
Unitholders equity, ending balance (in units)	2,300,000	2,300,000
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)		7,200,000
Unitholders equity, beginning balance		$ 174,261
Unitholders equity, ending balance (in units)	7,200,000	7,200,000
Unitholders equity, ending balance	$ 174,261	$ 174,261
Incentive Distribution Equity
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance (in units)		100,000
Unitholders equity, beginning balance		$ 30,814
Unitholders equity, ending balance (in units)	100,000	100,000
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)		72,595,000
Unitholders equity, beginning balance		$ (531,794)
Unit-based compensation		$ 579
Vesting of restricted and phantom units (in units)		339,000
Units issued in exchange for Standstill Agreement (in units)		3,800,000
Units issued in exchange for Standstill Agreement		$ 5,928
Net income		$ 13,670
Unitholders equity, ending balance (in units)	76,794,000	76,794,000
Unitholders equity, ending balance	$ (511,095)	$ (511,095)
Partners' Deficit | General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Unitholders equity, beginning balance		(160)
Net income		3
Unitholders equity, ending balance	$ (157)	(157)
Director
Increase (Decrease) in Partners' Capital [Roll Forward]
Unit-based compensation		$ 522
Director | Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Unit-based compensation (in units)		60,000
Unit-based compensation		$ 522

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Cash flows from operating activities:
Net income		$ (50,709)	$ (11,077)	$ 13,673	$ 5,295
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		38,139	27,689	74,686	56,485
Amortization of debt discount and issuance costs				10,752	3,713
Gain on extinguishment of debt		0	0	(51,693)	0
Impairment of long-lived assets		35,381	1,821	35,381	9,883
(Gain) loss on derivatives				10,052	(49,942)
Equity in income of equity method investees		(3)	(1)	(20)	(12)
Unit-based compensation				24,994	2,827
(Gain) loss on disposal of assets		(1,145)	11,049	(21,540)	5,525
Changes in assets and liabilities:
Decrease in accounts receivable, oil and natural gas				5,079	1,003
Decrease (increase) in accounts receivable, joint interest owners				10,905	(3,259)
Increase in accounts receivable, other				(4)	(399)
(Increase) decrease in other assets				(880)	148
Decrease in accounts payable				(6,467)	(109)
Increase in accrued oil and natural gas liabilities				12,035	8,519
Decrease in other liabilities				(1,989)	(4,558)
Total adjustments				101,311	29,836
Net cash provided by operating activities				114,984	35,131
Cash flows from investing activities:
Investment in oil and natural gas properties				(118,324)	(61,910)
Proceeds (costs) associated with sale of assets				29,235	(199)
Investment in other equipment				(130)	(110)
Net cash settlements (paid) received on commodity derivatives				(5,209)	10,807
Net cash used in investing activities				(94,428)	(51,412)
Cash flows from financing activities:
Proceeds from long-term debt				382,626	211,000
Payments of long-term debt				(375,384)	(196,000)
Payments of debt issuance costs				(23,096)	(60)
Net cash (used in) provided by financing activities				(15,854)	14,940
Net increase (decrease) in cash and cash equivalents				4,702	(1,341)
Cash, beginning of period (1)	[1]			4,450	5,747	$ 5,747
Cash, end of period (1)	[1]	9,152	4,406	9,152	4,406	4,450
Non-cash investing and financing activities:
Asset retirement obligation costs and liabilities				39	0
Asset retirement obligations associated with properties sold				(16,107)	(5,650)
Asset retirement obligations associated with property acquisitions				156	0
Note receivable received in exchange for sale of oil and natural gas properties				0	748
Units issued in exchange for Standstill Agreement				5,928	0
Change in accrued capital expenditures				25,733	0
Restricted Cash		$ 3,200	$ 3,200	$ 3,200	$ 3,200	$ 3,200
[1]	Inclusive of $3.2 million of restricted cash as of June 30, 2018 and 2017. See "—Footnote 1—Summary of Significant Accounting Policies" for further discussion

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2018
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, 2018 and for the three and six months ended June 30, 2018 and 2017 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, 2017 . 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 0.02% 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) Recent Developments On March 26, 2018, the Partnership announced its intent to consummate a transaction, pursuant to an agreement and plan of merger (the "Initial Merger Agreement"), that would result in the Partnership and LRGPLLC becoming subsidiaries of a newly formed Delaware corporation, Legacy Reserves Inc. (“New Legacy”), and the Partnership’s unitholders and preferred unitholders becoming common stockholders of New Legacy (such Transaction referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization: • New Legacy, which is currently a wholly owned subsidiary of LRGPLLC, will acquire all of the issued and outstanding limited liability company interests in LRGPLLC and will become the sole member of LRGPLLC; and • the Partnership will merge with Legacy Reserves Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of New Legacy ("Merger Sub"), with the Partnership continuing as the surviving entity and as a subsidiary of New Legacy (the “Merger”), the limited partner interests of the Partnership other than the incentive distribution units in the Partnership being exchanged for New Legacy common stock and the general partner interest remaining outstanding. On June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in a consolidated class action challenging the Merger that was filed in the Court of Chancery of the State of Delaware (the “Court”) reached an agreement in principal to settle the consolidated action. The parties submitted a stipulation and agreement of settlement (the “Settlement Agreement”) to the Court on July 6, 2018. The Court has entered a scheduling order setting September 12, 2018 as the date for a hearing for consideration of the Settlement Agreement. See Note 7 and Note 14 for further discussion of the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement. On July 9, 2018, New Legacy, the Partnership, LRGPLLC and Merger Sub entered into an Amended and Restated Agreement and Plan of Merger (the “A&R Merger Agreement”). The A&R Merger Agreement amends the Initial Merger Agreement to provide, among other things, that (i) with respect to the 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series A Preferred Units”), each Series A Preferred Unit will be converted into the right to receive 2.92033118 shares of common stock in New Legacy, (ii) with respect to the 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series B Preferred Units”), each Series B Preferred Unit will be converted into the right to receive 2.90650421 shares of common stock in New Legacy, (iii) for the purposes of clarification, phantom units that settle in units representing limited partner interests in the Partnership are included in the definition of “Restricted Unit”, and (iv) the board of directors of LRGPLLC shall take all necessary actions to allow the Partnership’s unitholders to vote at a special meeting of the unitholders (the “Special Meeting”) on a proposal to approve the classification of the board of directors of New Legacy, to be in effect following the closing of the A&R Merger Agreement (the “Classified Board Proposal”). As of June 30, 2018, Legacy’s ratio of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0, in violation of a covenant contained in the Current Credit Agreement. On July 31, 2018, Legacy received a waiver with respect to compliance with such covenant for the fiscal quarter ended June 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of June 30, 2018 , Legacy was in compliance with all financial and other covenants of the Current Credit Agreement. Legacy's Revolving Credit Agreement became a current liability as of April 1, 2018 as the credit facility matures on April 1, 2019. Legacy expects to refinance or extend the maturity of this obligation prior to its expiration date and Legacy believes that the consummation of the Corporate Reorganization will improve its ability to do so; however, there is no assurance that Legacy will be able to execute this refinancing or extension or, if Legacy is able to refinance or extend this obligation, that the terms of such refinancing or extension would be as favorable as the terms of Legacy's existing Revolving Credit Agreement. If the Corporate Reorganization is not consummated, Legacy believes its ability to refinance or extend the maturity of the Revolving Credit Agreement will be limited. Legacy anticipates that the Corporate Reorganization will close in September of 2018, but there is no assurance of any timing, if at all. (c) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of June 30, 2018 and December 31, 2017 : June 30, December 31, (In thousands) Accrued capital expenditures $ 58,931 $ 33,198 Accrued lease operating expense 18,493 18,179 Revenue payable to joint interest owners 26,831 18,510 Accrued ad valorem tax 8,956 5,807 Other 5,875 5,624 $ 119,086 $ 81,318 (d) Restricted Cash Restricted cash on our Consolidated Balance Sheet as of June 30, 2018 and December 31, 2017 is $3.2 million in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. Legacy adopted Accounting Standards Update ("ASU") No. 2016-18, "Restricted Cash" as of January 1, 2018. (e) Recent Accounting Pronouncements In February 2016, the FASB issued ASU 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 currently 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. In January 2018, the FASB issued an Exposure Draft titled “Leases (Topic 842): Targeted Improvements,” which includes a proposed amendment to ASU 2016-02 allowing entities an additional transition method to the existing requirements. Under this additional transition method, an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Legacy is currently evaluating the impact of its pending adoption of ASU 2016-02 on its consolidated financial statements. Legacy's ASU 2016-02 implementation approach includes educating key stakeholders within the organization, analyzing systems reports to identify the types and volume of contracts that may meet the definition of a lease under ASU 2016-02 and performing a detailed review of material contracts identified through that analysis. Based on the results obtained, Legacy will assess what impacts ASU 2016-02 could have on its financial statements and disclosures, existing accounting policies and internal controls, as well as whether a financial lease accounting system solution will need to be implemented to comply. Legacy is also in the process of evaluating ASU 2016-02’s currently available and proposed practical expedients upon transition.

Debt

Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Debt Debt consists of the following as of June 30, 2018 and December 31, 2017 : June 30, December 31, 2018 2017 (In thousands) Current debt Credit Facility due 2019 $ 508,000 $ — Unamortized debt issuance costs (2,778 ) — Total current debt, net 505,222 — Long-term debt Credit Facility due 2019 — 499,000 Second Lien Term Loans due 2020 338,626 205,000 8% Senior Notes due 2020 232,989 232,989 6.625% Senior Notes due 2021 245,579 432,656 817,194 1,369,645 Unamortized discount on Second Lien Term Loans and Senior Notes (12,228 ) (13,101 ) Unamortized debt issuance costs (20,213 ) (9,775 ) Total long-term debt, net $ 784,753 $ 1,346,769 Total debt, net $ 1,289,975 $ 1,346,769 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 (as amended, 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 $575 million as part of the spring 2018 redetermination. 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 2018. 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 (i) 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 or (ii) Legacy has unused lender commitments of not less than 15% of the total lender commitments then in effect. The Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows: • as of any day, 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 2.50 to 1.00; • as of the last day of any fiscal quarter, 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 any fiscal 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 • as of the last day of any fiscal quarter, 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 as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be (giving pro forma effect to material acquisitions or dispositions since the date of such reports) (“PDP PV-10”), (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. On March 23, 2018, the Partnership entered into an amendment to the Current Credit Agreement (the “Current Credit Agreement Amendment”). The Current Credit Agreement Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Current Credit Agreement to, among other items: • permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure; • provide that New Legacy and LRGPLLC will guarantee the debt outstanding under the Current Credit Agreement; • provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Current Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy; • waive any “Change in Control” (as defined in the Current Credit Agreement) triggered by the Corporate Reorganization; and • permit redemptions of the 2020 Senior Notes, 2021 Senior Notes and loans under the Second Lien Term Loan Credit Agreement (as defined below) with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy. 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, 2018, Legacy’s ratio of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0, in violation of a covenant contained in the Current Credit Agreement. On July 31, 2018, Legacy received a waiver with respect to compliance with such covenant for the fiscal quarter ended June 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of June 30, 2018 , 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 Current Credit Agreement, which would constitute a default under its Current Credit Agreement. 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 Current Credit Agreement and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under its Current Credit Agreement 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 (as defined below), 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, 2018 , Legacy had approximately $508 million drawn under the Current Credit Agreement at a weighted-average interest rate of 4.76% , leaving approximately $66.2 million of availability under the Current Credit Agreement. For the six -month period ended June 30, 2018 , Legacy paid in cash $12.7 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 (as amended, 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”). The Second Lien Term Loans under the Second Lien Term Loan Credit Agreement are issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash or, prior to the 18 month anniversary of the Second Lien Term Loan Credit Agreement, Legacy may elect to pay in kind up to 50% of the interest payable. 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 Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Term Loan Credit Agreement will mature on August 1, 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, 2018 , Legacy had approximately $338.6 million drawn under the Second Lien Term Loan Credit Agreement. On December 31, 2017, Legacy entered into the Third Amendment to the Second Lien Term Loan Credit Agreement (the "Third Amendment") among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, including GSO and certain funds and accounts managed, advised or sub-advised by GSO, which, among other things, increased the maximum amount available for borrowing under the Second Lien Term Loans to $400.0 million , extended the availability of undrawn principal ( $61.4 million of availability as of June 30, 2018 ) to October 25, 2019 and relaxed the asset coverage ratio to 0.85 to 1.00 until the fiscal quarter ended December 31, 2018. The Third Amendment became effective on January 5, 2018. 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 (i) 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 or (ii) Legacy has unused lender commitments of not less than 15% of the total lender commitments then in effect. The Second Lien Term Loan Credit Agreement also contains covenants that, among other things, requires Legacy to: • not permit, as of the last day of any fiscal quarter, 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 0.85 to 1.00 until the fiscal quarter ended December 31, 2018 and 1.00 to 1.00 thereafter; 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. On March 23, 2018, the Partnership entered into the Fourth Amendment to the Second Lien Term Loan Credit Agreement (the “Term Loan Amendment”). The Term Loan Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Second Lien Term Loan Credit Agreement to, among other items: • permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure; • provide that New Legacy and LRGPLLC will guarantee the debt outstanding under the Second Lien Term Loan Credit Agreement; • provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Second Lien Term Loan Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy; • waive any “Change in Control” (as defined in the Second Lien Term Loan Credit Agreement) triggered by the Corporate Reorganization; • waive any requirement to prepay the Term Loans using the Partnership’s Free Cash Flow or limit Capital Expenditures (each as defined in the Second Lien Term Loan Credit Agreement) prior to March 31, 2019; and • permit redemptions of the 2020 Senior Notes and the 2021 Senior Notes with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy. 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, 2018 , Legacy was in compliance with all financial and other covenants of the Second Lien Term Loan Credit Agreement. 8% Senior Notes Due 2020 ("2020 Senior Notes") 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 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 as supplemented. 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 13—Subsidiary Guarantors" for further details on Legacy's guarantors. The indenture governing the 2020 Senior Notes (the "2020 Notes Indenture") 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. On April 2, 2018, following receipt of the requisite consents of the holders of the 2020 Senior Notes, the Partnership entered into the Second Supplemental Indenture (the “2020 Notes Supplemental Indenture”), to the 2020 Notes Indenture. Pursuant to the 2020 Notes Supplemental Indenture, the 2020 Notes Indenture was amended to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the 2020 Notes Indenture, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2020 Senior Notes by New Legacy and LRGPLLC, (iv) provide that certain covenants and other provisions under the 2020 Notes Indenture previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes. 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. 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. 6.625% Senior Notes Due 2021 ("2021 Senior Notes") 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 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 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 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, as supplemented. 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. On April 2, 2018, following receipt of the requisite consents of the holders of the 2021 Senior Notes, the Partnership entered into the Second Supplemental Indenture (the “2021 Notes Supplemental Indenture”) to the initial indenture governing the 2021 Notes (the "2021 Notes Indenture"). Pursuant to the 2021 Notes Supplemental Indenture, the 2021 Notes Indenture was amended to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the 2021 Notes Indenture, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2021 Senior Notes by New Legacy and LRGPLLC, (iv) provide that certain covenants and other provisions under the 2021 Notes Indenture previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes. 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. On December 31, 2017, Legacy entered into a definitive agreement with certain funds managed by Fir Tree Partners ("Fir Tree") pursuant to which Legacy acquired $187.0 million of the 6.625% Notes for a price of approximately $132 million inclusive of accrued but unpaid interest with a settlement date of January 5, 2018. Legacy treated these repurchases for accounting purposes as an extinguishment of debt. Accordingly, Legacy recognized a gain of $51.7 million 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.

Impact of ASC 606 Adoption

Impact of ASC 606 Adoption	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Impact of ASC 606 Adoption	Impact of ASC 606 Adoption On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606 - Revenue from Contracts with Customers ("ASC 606"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP and includes a five step process 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. The impact of adoption on Legacy's current period results is as follows (in thousands): Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change (In thousands) Revenues: Oil Sales $ 99,799 $ 99,936 $ (137 ) $ 193,210 $ 193,379 $ (169 ) Natural gas liquids (NGL) sales 5,735 5,898 (163 ) 13,131 13,443 (312 ) Natural gas sales 33,747 35,452 (1,705 ) 70,419 73,585 (3,166 ) $ 139,281 $ 141,286 $ (2,005 ) $ 276,760 $ 280,407 $ (3,647 ) Costs and expenses: Oil and natural gas production $ 49,431 $ 51,436 $ (2,005 ) $ 97,398 $ 101,045 $ (3,647 ) Net income (loss) $ (50,709 ) $ (50,709 ) $ — $ 13,673 $ 13,673 $ — Partners' deficit, as of January 1, 2018 $ (271,687 ) $ (271,687 ) $ — $ (271,687 ) $ (271,687 ) $ — The change to oil sales and a related change to oil production expense are due to the conclusion that Legacy transfers control of oil production to purchasers at or near the wellhead. As such, certain transportation expenses that are deducted from the sales price Legacy receives from the purchaser are presented net in revenue in accordance with ASC 606. This represents a change from Legacy's prior practice under ASC 605 of presenting those transportation costs gross as an oil and natural gas production expense. The change to natural gas and NGL sales and the related change to natural gas production expense are due to the conclusion that Legacy represents an agent in certain gas processing agreements with midstream entities in accordance with the control model in ASC 606. This represents a change from Legacy's previous conclusion utilizing the principal versus agent indicators under ASC 605 that Legacy acted as the principal in those arrangements. As a result, Legacy is required to present certain gathering and processing expenses net in natural gas and NGL sales under ASC 606. Revenue from Contracts with Customers Oil, NGL and natural gas sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. This generally occurs when oil or natural gas has been delivered to a pipeline or truck. A more detailed summary of the sale of each product type is included below. Oil Sales Legacy's oil sales contracts are generally structured such that Legacy sells its oil production to the purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality and physical location. Legacy recognizes revenue when control transfers to the purchaser upon delivery at the net price received from purchaser. NGL and Natural Gas Sales Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. In these scenarios, Legacy evaluates whether it is the principal or the agent in the transaction. In virtually all of Legacy's gas processing contracts, Legacy has concluded that it is the agent, and the midstream processing entity is Legacy's customer. Accordingly, Legacy recognizes revenue upon delivery based on the net amount of the proceeds received from the midstream processing entity. Proceeds are generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses. Under Legacy's dry gas sales that do not require processing, Legacy sells its natural gas production to third party purchasers at a contractually specified delivery point at or near the wellhead. Pricing provisions are tied to a market index, with certain deductions based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. Legacy recognizes revenue upon delivery of the natural gas to third party purchasers based on the relevant index price net of deductions. Imbalances Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2017 and 2016. Disaggregation of Revenue Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below. Three Months Ended Six Months Ended June 30, 2018 2018 (In thousands) Revenues: Oil sales $ 99,799 $ 193,210 Natural gas liquids (NGL) sales 5,735 13,131 Natural gas sales 33,747 70,419 Total revenues 139,281 276,760 Significant Judgments Principal versus agent Legacy engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Legacy's behalf, such as Legacy's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether Legacy is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. Transaction price allocated to remaining performance obligations A significant number of Legacy's product sales are short-term in nature with a contract term of one year or less. For those contracts, Legacy has utilized the practical expedient in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For Legacy's product sales that have a contract term greater than one year, Legacy has utilized the practical expedient in ASC 606 that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under Legacy's product sales contracts, it is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and record invoiced amounts as “Accounts receivable - oil and natural gas” in its consolidated balance sheet. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. In this scenario, payment is also unconditional, as Legacy has satisfied its performance obligations through delivery of the relevant product. As a result, Legacy has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations Legacy records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Legacy is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated. Legacy records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Legacy has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended June 30, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Impact of ASC 606 Adoption On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606 - Revenue from Contracts with Customers ("ASC 606"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP and includes a five step process 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. The impact of adoption on Legacy's current period results is as follows (in thousands): Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change (In thousands) Revenues: Oil Sales $ 99,799 $ 99,936 $ (137 ) $ 193,210 $ 193,379 $ (169 ) Natural gas liquids (NGL) sales 5,735 5,898 (163 ) 13,131 13,443 (312 ) Natural gas sales 33,747 35,452 (1,705 ) 70,419 73,585 (3,166 ) $ 139,281 $ 141,286 $ (2,005 ) $ 276,760 $ 280,407 $ (3,647 ) Costs and expenses: Oil and natural gas production $ 49,431 $ 51,436 $ (2,005 ) $ 97,398 $ 101,045 $ (3,647 ) Net income (loss) $ (50,709 ) $ (50,709 ) $ — $ 13,673 $ 13,673 $ — Partners' deficit, as of January 1, 2018 $ (271,687 ) $ (271,687 ) $ — $ (271,687 ) $ (271,687 ) $ — The change to oil sales and a related change to oil production expense are due to the conclusion that Legacy transfers control of oil production to purchasers at or near the wellhead. As such, certain transportation expenses that are deducted from the sales price Legacy receives from the purchaser are presented net in revenue in accordance with ASC 606. This represents a change from Legacy's prior practice under ASC 605 of presenting those transportation costs gross as an oil and natural gas production expense. The change to natural gas and NGL sales and the related change to natural gas production expense are due to the conclusion that Legacy represents an agent in certain gas processing agreements with midstream entities in accordance with the control model in ASC 606. This represents a change from Legacy's previous conclusion utilizing the principal versus agent indicators under ASC 605 that Legacy acted as the principal in those arrangements. As a result, Legacy is required to present certain gathering and processing expenses net in natural gas and NGL sales under ASC 606. Revenue from Contracts with Customers Oil, NGL and natural gas sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. This generally occurs when oil or natural gas has been delivered to a pipeline or truck. A more detailed summary of the sale of each product type is included below. Oil Sales Legacy's oil sales contracts are generally structured such that Legacy sells its oil production to the purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality and physical location. Legacy recognizes revenue when control transfers to the purchaser upon delivery at the net price received from purchaser. NGL and Natural Gas Sales Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. In these scenarios, Legacy evaluates whether it is the principal or the agent in the transaction. In virtually all of Legacy's gas processing contracts, Legacy has concluded that it is the agent, and the midstream processing entity is Legacy's customer. Accordingly, Legacy recognizes revenue upon delivery based on the net amount of the proceeds received from the midstream processing entity. Proceeds are generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses. Under Legacy's dry gas sales that do not require processing, Legacy sells its natural gas production to third party purchasers at a contractually specified delivery point at or near the wellhead. Pricing provisions are tied to a market index, with certain deductions based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. Legacy recognizes revenue upon delivery of the natural gas to third party purchasers based on the relevant index price net of deductions. Imbalances Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2017 and 2016. Disaggregation of Revenue Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below. Three Months Ended Six Months Ended June 30, 2018 2018 (In thousands) Revenues: Oil sales $ 99,799 $ 193,210 Natural gas liquids (NGL) sales 5,735 13,131 Natural gas sales 33,747 70,419 Total revenues 139,281 276,760 Significant Judgments Principal versus agent Legacy engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Legacy's behalf, such as Legacy's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether Legacy is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. Transaction price allocated to remaining performance obligations A significant number of Legacy's product sales are short-term in nature with a contract term of one year or less. For those contracts, Legacy has utilized the practical expedient in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For Legacy's product sales that have a contract term greater than one year, Legacy has utilized the practical expedient in ASC 606 that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under Legacy's product sales contracts, it is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and record invoiced amounts as “Accounts receivable - oil and natural gas” in its consolidated balance sheet. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. In this scenario, payment is also unconditional, as Legacy has satisfied its performance obligations through delivery of the relevant product. As a result, Legacy has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations Legacy records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Legacy is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated. Legacy records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Legacy has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended June 30, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Asset Acquisition and Dispositi

Asset Acquisition and Dispositions	6 Months Ended
	Jun. 30, 2018
Business Combinations [Abstract]
Asset Acquisition and Dispositions	Asset Acquisition and Dispositions On August 1, 2017, Legacy made a payment in the amount of $141 million (the “Acceleration Payment”) in connection with its First Amended and Restated Development Agreement (the “Restated Agreement”) with Jupiter JV, LP (“Jupiter”). The Acceleration Payment caused the reversion to Legacy of additional working interests in all wells and associated personal property and infrastructure (collectively, the “Wells”) and all undeveloped assets subject to the Restated Agreement. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties. During the six months ended June 30, 2018 , Legacy divested certain individually immaterial oil and natural gas assets for net cash proceeds of $29.2 million . These dispositions were treated as asset sales and resulted in a gain on disposition of assets of $21.5 million during the period.

Related Party Transactions (Not

Related Party Transactions (Notes)	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Related Party Transactions Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown and Dale A. Brown, both directors of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $120,241 and $9,758 in the six month periods ended June 30, 2018 and 2017 , respectively, to Blue Quail for such services. Blue Quail charged Legacy prices consistent with that of other vendors for services rendered.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies On March 28, 2018, a purported holder of the Partnership’s Preferred Units filed a putative class action challenging the Merger against the Partnership, LRGPLLC and New Legacy (the “Doppelt Action”). The Doppelt Action contains two causes of action challenging the Merger, including breach of the Fifth Amended and Restated Agreement of Limited Partnership of the Partnership (the "Partnership Agreement") and breach of the implied covenant of good faith and fair dealing. The plaintiff in the Doppelt Action seeks injunctive relief prohibiting consummation of the Merger or, in the event the Merger is consummated, rescission or rescissory damages, as well as reasonable attorneys’ and experts’ fees and expenses. Additionally, on April 4, 2018, a motion to expedite was filed in connection with the Doppelt Action, by which the plaintiff sought a hearing on a motion for a preliminary injunction prior to the close of the Merger and requested that the court set an expedited discovery schedule prior to any such hearing. The plaintiff in the Doppelt Action also filed a lawsuit against the Partnership and the LRGPLLC in 2017 for breach of the Partnership Agreement based on the treatment of the accrued but unpaid preferred distributions as “guaranteed payments” for tax purposes. A second putative class action lawsuit challenging the Merger was filed on April 3, 2018 against the Partnership, the LRGPLLC and New Legacy (the “Chammah Ventures Action”). The Chammah Ventures Action contains the same causes of action and that plaintiff seeks substantially the same relief as the plaintiff in the Doppelt Action. On April 13, 2018, the Court issued an order consolidating the Doppelt and Chammah actions (together, the "Consolidated Actions") and appointing Plaintiff Doppelt as lead plaintiff and his counsel as lead counsel for the putative class action. On April 13, 2018, the Court also granted the motion to expedite the consolidated action. On April 23, 2018 Plaintiff Doppelt filed an Amended Complaint, adding an additional count for breach of the Partnership Agreement. A hearing on Plaintiff's motion for a preliminary injunction and Legacy's motion to dismiss occurred on June 4, 2018. On June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in the Consolidated Action reached an agreement in principle to settle the Consolidated Action. The parties submitted a Settlement Agreement to the Court on July 6, 2018. The Court has entered a scheduling order setting September 12, 2018 as the date for a hearing for consideration of the Settlement Agreement. See Note 1 and Note 14 for further discussion of the Settlement Agreement. A third putative class action lawsuit challenging the Merger was filed against the Partnership, LRGPLLC, New Legacy and Merger Sub on April 27, 2018 by Patrick Irish in the District Court in Midland County, Texas (the “Irish Action”). The Irish Action contains the same general causes of action as the initial complaint filed in the Doppelt Action and the Chammah Ventures Action and seeks the same relief. The Partnership, LRGPLLC, New Legacy and the plaintiff’s counsel in the Consolidated Action have agreed to coordinate efforts to obtain a dismissal of the Irish Action following the consummation of the Merger. The Partnership cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this quarterly report, nor can the Partnership predict the amount of time and expense that will be required to resolve such litigation. The Partnership believes the lawsuits are without merit and intends to vigorously defend against the lawsuits. Legacy is also, from time to time, involved in litigation and claims arising out of its operations in the normal course of business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on Legacy’s consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on Legacy cannot be predicted with certainty. Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected. Legacy has employment agreements with its officers and retention bonus agreements with 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, 2018
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 tables summarize (i) the valuation of each of Legacy’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the financial instruments are subject to netting arrangements and qualify for net presentation in the Legacy’s consolidated balance sheets at June 30, 2018 and December 31, 2017 . Legacy nets the fair value of derivative instruments by counterparty in its consolidated balance sheets. June 30, 2018 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Assets: Current Commodity derivatives $ — $ 12,703 $ 30,134 $ 42,837 $ (12,703 ) $ 30,134 Interest rate derivatives — 2,300 — 2,300 — 2,300 Noncurrent Commodity derivatives — 7,701 1,482 9,183 (4,388 ) 4,795 Interest rate derivatives — 784 — 784 — 784 Liabilities: Current Commodity derivatives — (44,830 ) — (44,830 ) 12,703 (32,127 ) LTIP liability — (25,840 ) — (25,840 ) — (25,840 ) Noncurrent Commodity derivatives — (6,682 ) — (6,682 ) 4,388 (2,294 ) Net fair value instruments $ — $ (53,864 ) $ 31,616 $ (22,248 ) $ — $ (22,248 ) (a) See Note 12 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. December 31, 2017 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Assets: Current Commodity derivatives $ — $ 19,792 $ — $ 19,792 $ (7,204 ) $ 12,588 Interest rate derivatives — 837 — 837 (1 ) 836 Noncurrent Commodity derivatives — 14,278 — 14,278 (1,460 ) 12,818 Interest rate derivatives — 1,281 — 1,281 1,281 Liabilities: Current Commodity derivatives — (21,027 ) (4,191 ) (25,218 ) 7,204 (18,014 ) Interest rate derivatives — (1 ) — (1 ) 1 — LTIP liability — (1,947 ) — (1,947 ) (1,947 ) Noncurrent Commodity derivatives — (1,637 ) (897 ) (2,534 ) 1,460 (1,074 ) Net fair value instruments $ — $ 11,576 $ (5,088 ) $ 6,488 $ — $ 6,488 (a) See Note 12 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 2018 2017 2018 2017 (In thousands) Beginning balance $ 9,909 $ 1,666 $ (5,088 ) $ 8 Total gains (losses) 26,356 (747 ) 40,416 492 Settlements, net (4,649 ) (289 ) (3,712 ) 130 Ending balance $ 31,616 $ 630 $ 31,616 $ 630 Gains (losses) included in earnings relating to derivatives still held as of June 30, 2018 and 2017 $ 23,158 $ (631 ) $ 34,232 $ 89 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 10. Nonrecurring fair value measurements of proved oil and natural gas properties during the six -month period ended June 30, 2018 consist of: Fair Value Measurements During the Six Months Ended June 30, 2018 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) $ — $ — $ 26,195 (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, 2018 , Legacy incurred impairment charges of $35.4 million as oil and natural gas properties with a net cost basis of $61.6 million were written down to their fair value of $26.2 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 $508 million as of June 30, 2018 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 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, 2018 , the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $195.1 million and $196.5 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, 2018
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, 2018 and 2017 : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Beginning fair value of commodity derivatives $ 7,409 $ 43,131 $ 6,318 $ 12,698 Total gain (loss) - oil derivatives (7,082 ) 7,776 (7,824 ) 22,776 Total gain (loss) - natural gas derivatives (2,233 ) 6,740 (3,195 ) 26,409 Crude oil derivative cash settlements paid (received) 6,309 (3,559 ) 11,203 (6,698 ) Natural gas derivative cash settlements received (3,895 ) (3,012 ) (5,994 ) (4,109 ) Ending fair value of commodity derivatives $ 508 $ 51,076 $ 508 $ 51,076 As of June 30, 2018 , 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 2018 1,527,200 $54.76 $51.20 - $63.68 2019 2,190,000 $58.88 $57.15 - $61.20 As of June 30, 2018 , 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 2018 2,024,000 $(1.13) $(1.25) - $(0.80) 2019 730,000 $(1.15) $(1.15) As of June 30, 2018 , 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 2018 782,000 $47.06 $60.29 As of June 30, 2018 , 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 2018 64,400 $57.00 $82.00 $90.50 As of June 30, 2018 , 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 2018 18,160,000 $3.23 $3.04 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39 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, 2018 2017 2018 2017 (In thousands) Beginning fair value of interest rate swaps $ 2,983 $ 1,025 $ 2,117 $ 183 Total gain on interest rate swaps 372 (334 ) 1,315 90 Cash settlements (received) paid (271 ) 249 (348 ) 667 Ending fair value of interest rate swaps $ 3,084 $ 940 $ 3,084 $ 940 The table below summarizes the interest rate swap position as of June 30, 2018 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2018 (Dollars in thousands) $ 235,000 1.363 % 9/1/2015 9/1/2019 $ 3,084

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2018
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, 2018 and year ended December 31, 2017 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 274,686 $ 272,148 Liabilities incurred with properties acquired 156 62 Liabilities incurred with properties drilled 39 39 Liabilities settled during the period (812 ) (1,891 ) Liabilities associated with properties sold (16,107 ) (8,464 ) Current period accretion 6,283 12,792 Asset retirement obligation - end of period $ 264,245 $ 274,686

Partners' Deficit

Partners' Deficit	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Partners' Deficit	Partners' Deficit Preferred Units As of June 30, 2018 , 2,300,000 of Legacy's 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") were outstanding. As of June 30, 2018 , 7,200,000 of Legacy's 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") were outstanding 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, 2018 , $4.92 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $46.7 million . Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 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. 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 pursuant to the terms of the IDR Holders Agreement. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units. The Incentive Distribution Units represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets are set above the current levels of Legacy's distributions to unitholders. 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 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, as defined in Legacy's Partnership Agreement, for such quarter. Further, WPX also has the ability to similarly convert any of its vested Incentive Distribution Units. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX. Income (loss) per unit The following table sets forth the computation of basic and diluted income per unit: Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (In thousands) Net income (loss) $ (50,709 ) $ (11,077 ) $ 13,673 $ 5,295 Distributions to preferred unitholders (4,750 ) (4,750 ) (9,500 ) (9,500 ) Net income (loss) attributable to unitholders $ (55,459 ) $ (15,827 ) 4,173 (4,205 ) Weighted average number of units outstanding - basic 76,725 72,354 76,539 72,229 Effect of dilutive securities: Restricted and phantom units — — 894 — Weighted average number of units outstanding - diluted 76,725 72,354 77,433 72,229 Basic & diluted income (loss) per unit $ (0.72 ) $ (0.22 ) $ 0.05 $ (0.06 ) For the three months ended June 30, 2018 , 135,089 restricted units and 1,424,114 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect. For the six months ended June 30, 2018 , 57,625 restricted units and 607,488 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, 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.

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2018
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, 2018 , grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 3,459,197 units had been made, comprised of 266,014 unit option awards, 988,207 restricted unit awards, 1,424,114 phantom unit awards and 780,862 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, 2017 or the six -month period ended June 30, 2018 . For the six -month periods ended June 30, 2018 and 2017 , Legacy recorded $1.5 million and $(0.1) million , respectively, of compensation (benefit) expense due to the change in liability from December 31, 2017 and 2016 , respectively, based on its use of the Black-Scholes model to estimate the June 30, 2018 and 2017 fair value of these UARs (see Note 7). As of June 30, 2018 , there was a total of approximately $0.1 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At June 30, 2018 , this cost was expected to be recognized over a weighted-average period of approximately 0.22 years. Compensation expense is based upon the fair value as of June 30, 2018 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 92% and employed the Black-Scholes model to estimate the June 30, 2018 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 5.6% . 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, 2018 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2018 722,021 $ 20.13 2.99 $ — Exercised (2,667 ) 4.80 Expired & Forfeited (22,167 ) 28.21 Outstanding at June 30, 2018 697,187 $ 19.93 2.87 $ 225,371 UARs exercisable at June 30, 2018 579,853 $ 22.81 2.60 $ 60,370 The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2018 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2018 129,499 $ 5.97 Vested (9,988 ) 8.95 Forfeited (2,167 ) 5.66 Non-vested at June 30, 2018 117,344 $ 5.72 Legacy has used a weighted-average risk-free interest rate of 2.6% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at June 30, 2018 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) 2.87 Risk free interest rate 2.6 % Annual distribution rate per unit $0.00 Volatility 91.7 % 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 February 21, 2017 , the Compensation Committee approved the award to Legacy's executive officers of 396,850 subjective, or service-based, phantom units that, upon vesting, settle in units, 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. The phantom units settled in units had a grant date fair value of $2.25 per unit. On February 16, 2018, the Compensation Committee approved the award to Legacy's executive officers of 635,590 subjective, or service-based, phantom units that, upon vesting, settle in units, 317,794 subjective phantom units that, upon vesting, settle in cash and a maximum of 3,813,536 objective, or performance-based, phantom units that, upon vesting, settle in cash. The phantom units had a grant date fair value of $3.69 per unit. Compensation expense related to the phantom units was $23.2 million and $1.9 million for the six months ended June 30, 2018 and 2017 , respectively. As of June 30, 2018 , there was a total of $38.6 million of unrecognized compensation expense remaining. This cost is expected to be recognized over a weighted average period of approximately 2.2 years. Restricted Units Legacy did not issue restricted units to any employees during the year ended December 31, 2017 or the six -month period ended June 30, 2018 . Compensation expense related to restricted units was $0.4 million and $1.0 million for the six months ended June 30, 2018 and 2017 , respectively. As of June 30, 2018 , there was a total of $0.4 million of unrecognized compensation expense related to the unvested portion of these restricted units. At June 30, 2018 , 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, 2018 , do not include 135,089 units related to unvested restricted unit awards. Board Units 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. On May 15, 2018, Legacy granted and issued 12,019 units to four non-employee directors who are anticipated to serve on the Board of Directors of New Legacy and 6,010 units to two non-employee directors who are not anticipated to serve on the Board of Directors of New Legacy. The value of each unit was $8.69 at the time of issuance.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2018
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—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, 2018
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in the Consolidated Action reached an agreement in principle to settle the Consolidated Action. The parties submitted the Settlement Agreement to the Court on July 6, 2018 and, on July 11, 2018, the Court entered a scheduling order for consideration of the Settlement Agreement (the “Scheduling Order”). The Scheduling Order sets September 12, 2018 as the date for the hearing at which the Court will consider (i) the fairness of the Settlement Agreement; (ii) whether a judgment should be entered dismissing the Consolidated Action with prejudice; (iii) the plaintiff’s counsel’s application for fees and expenses; and (iv) any objections to the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement. In exchange, the class of holders of Preferred Units (dating back to January 21, 2016 through the consummation of the Merger) have agreed to release the Partnership, LRGPLLC and New Legacy, and any of their parent entities, controlling persons, associates, affiliates, including any person or entity owning, directly or indirectly, any portion of LRGPLLC, or subsidiaries and each and all of their respective officers, directors, stockholders, employees, representatives, advisors, consultants and other released parties, from liability for any claims related to or arising out of the rights inhering to the Preferred Units (subject to limited exceptions related to tax liabilities), including all claims brought in the Consolidated Action. As part of the Settlement Agreement, the lawsuit filed against the Partnership and LRGPLLC by the Plaintiff in the Doppelt Action based on the treatment of the accrued but unpaid preferred distributions as "guaranteed payments" for tax purposes will be dismissed. Each of the administrative agent for the Current Credit Agreement and the majority lenders under the Second Lien Term Loan Credit Agreement have consented to the terms of the Settlement Agreement, as required pursuant to the terms of the Current Credit Agreement and the Second Lien Term Loan Credit Agreement, respectively. On July 9, 2018, New Legacy, the Partnership, LRGPLLC and Merger Sub entered into the A&R Merger Agreement. The A&R Merger Agreement amends the Initial Merger Agreement to provide, among other things, that (i) with respect to the Series A Preferred Units, each Series A Preferred Unit will be converted into the right to receive 2.92033118 shares of common stock in New Legacy, (ii) with respect to the Series B Preferred Units, each Series B Preferred Unit will be converted into the right to receive 2.90650421 shares of common stock in New Legacy, (iii) for the purposes of clarification, phantom units that settle in units representing limited partner interests in the Partnership are included in the definition of “Restricted Unit”, and (iv) the board of directors of LRGPLLC shall take all necessary actions to allow the Partnership’s unitholders to vote at the Special Meeting on the Classified Board Proposal. On July 31, 2018, the lenders for the Current Credit Agreement agreed to waive the Partnership’s compliance with the ratio of consolidated current assets to consolidated current liabilities covenant contained in the Current Credit Agreement for the fiscal quarter ended June 30, 2018.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
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, 2018 and for the three and six months ended June 30, 2018 and 2017 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, 2017 .
Restricted Cash	Restricted Cash Restricted cash on our Consolidated Balance Sheet as of June 30, 2018 and December 31, 2017 is $3.2 million in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. Legacy adopted Accounting Standards Update ("ASU") No. 2016-18, "Restricted Cash" as of January 1, 2018.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In February 2016, the FASB issued ASU 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 currently 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. In January 2018, the FASB issued an Exposure Draft titled “Leases (Topic 842): Targeted Improvements,” which includes a proposed amendment to ASU 2016-02 allowing entities an additional transition method to the existing requirements. Under this additional transition method, an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Legacy is currently evaluating the impact of its pending adoption of ASU 2016-02 on its consolidated financial statements. Legacy's ASU 2016-02 implementation approach includes educating key stakeholders within the organization, analyzing systems reports to identify the types and volume of contracts that may meet the definition of a lease under ASU 2016-02 and performing a detailed review of material contracts identified through that analysis. Based on the results obtained, Legacy will assess what impacts ASU 2016-02 could have on its financial statements and disclosures, existing accounting policies and internal controls, as well as whether a financial lease accounting system solution will need to be implemented to comply. Legacy is also in the process of evaluating ASU 2016-02’s currently available and proposed practical expedients upon transition.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
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, 2018 and December 31, 2017 : June 30, December 31, (In thousands) Accrued capital expenditures $ 58,931 $ 33,198 Accrued lease operating expense 18,493 18,179 Revenue payable to joint interest owners 26,831 18,510 Accrued ad valorem tax 8,956 5,807 Other 5,875 5,624 $ 119,086 $ 81,318

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of long-term debt	Debt consists of the following as of June 30, 2018 and December 31, 2017 : June 30, December 31, 2018 2017 (In thousands) Current debt Credit Facility due 2019 $ 508,000 $ — Unamortized debt issuance costs (2,778 ) — Total current debt, net 505,222 — Long-term debt Credit Facility due 2019 — 499,000 Second Lien Term Loans due 2020 338,626 205,000 8% Senior Notes due 2020 232,989 232,989 6.625% Senior Notes due 2021 245,579 432,656 817,194 1,369,645 Unamortized discount on Second Lien Term Loans and Senior Notes (12,228 ) (13,101 ) Unamortized debt issuance costs (20,213 ) (9,775 ) Total long-term debt, net $ 784,753 $ 1,346,769 Total debt, net $ 1,289,975 $ 1,346,769
Schedule of debt redemption	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 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 2018 101.656 % 2019 and thereafter 100.000 % 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 2017 102.000 % 2018 and thereafter 100.000 %

Impact of ASC 606 Adoption (Tab

Impact of ASC 606 Adoption (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Impact of ASC 606 Adoption	The impact of adoption on Legacy's current period results is as follows (in thousands): Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change (In thousands) Revenues: Oil Sales $ 99,799 $ 99,936 $ (137 ) $ 193,210 $ 193,379 $ (169 ) Natural gas liquids (NGL) sales 5,735 5,898 (163 ) 13,131 13,443 (312 ) Natural gas sales 33,747 35,452 (1,705 ) 70,419 73,585 (3,166 ) $ 139,281 $ 141,286 $ (2,005 ) $ 276,760 $ 280,407 $ (3,647 ) Costs and expenses: Oil and natural gas production $ 49,431 $ 51,436 $ (2,005 ) $ 97,398 $ 101,045 $ (3,647 ) Net income (loss) $ (50,709 ) $ (50,709 ) $ — $ 13,673 $ 13,673 $ — Partners' deficit, as of January 1, 2018 $ (271,687 ) $ (271,687 ) $ — $ (271,687 ) $ (271,687 ) $ — Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below. Three Months Ended Six Months Ended June 30, 2018 2018 (In thousands) Revenues: Oil sales $ 99,799 $ 193,210 Natural gas liquids (NGL) sales 5,735 13,131 Natural gas sales 33,747 70,419 Total revenues 139,281 276,760

Revenue from Contracts with C25

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The impact of adoption on Legacy's current period results is as follows (in thousands): Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change (In thousands) Revenues: Oil Sales $ 99,799 $ 99,936 $ (137 ) $ 193,210 $ 193,379 $ (169 ) Natural gas liquids (NGL) sales 5,735 5,898 (163 ) 13,131 13,443 (312 ) Natural gas sales 33,747 35,452 (1,705 ) 70,419 73,585 (3,166 ) $ 139,281 $ 141,286 $ (2,005 ) $ 276,760 $ 280,407 $ (3,647 ) Costs and expenses: Oil and natural gas production $ 49,431 $ 51,436 $ (2,005 ) $ 97,398 $ 101,045 $ (3,647 ) Net income (loss) $ (50,709 ) $ (50,709 ) $ — $ 13,673 $ 13,673 $ — Partners' deficit, as of January 1, 2018 $ (271,687 ) $ (271,687 ) $ — $ (271,687 ) $ (271,687 ) $ — Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below. Three Months Ended Six Months Ended June 30, 2018 2018 (In thousands) Revenues: Oil sales $ 99,799 $ 193,210 Natural gas liquids (NGL) sales 5,735 13,131 Natural gas sales 33,747 70,419 Total revenues 139,281 276,760

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis	The following tables summarize (i) the valuation of each of Legacy’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the financial instruments are subject to netting arrangements and qualify for net presentation in the Legacy’s consolidated balance sheets at June 30, 2018 and December 31, 2017 . Legacy nets the fair value of derivative instruments by counterparty in its consolidated balance sheets. June 30, 2018 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Assets: Current Commodity derivatives $ — $ 12,703 $ 30,134 $ 42,837 $ (12,703 ) $ 30,134 Interest rate derivatives — 2,300 — 2,300 — 2,300 Noncurrent Commodity derivatives — 7,701 1,482 9,183 (4,388 ) 4,795 Interest rate derivatives — 784 — 784 — 784 Liabilities: Current Commodity derivatives — (44,830 ) — (44,830 ) 12,703 (32,127 ) LTIP liability — (25,840 ) — (25,840 ) — (25,840 ) Noncurrent Commodity derivatives — (6,682 ) — (6,682 ) 4,388 (2,294 ) Net fair value instruments $ — $ (53,864 ) $ 31,616 $ (22,248 ) $ — $ (22,248 ) (a) See Note 12 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. December 31, 2017 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Assets: Current Commodity derivatives $ — $ 19,792 $ — $ 19,792 $ (7,204 ) $ 12,588 Interest rate derivatives — 837 — 837 (1 ) 836 Noncurrent Commodity derivatives — 14,278 — 14,278 (1,460 ) 12,818 Interest rate derivatives — 1,281 — 1,281 1,281 Liabilities: Current Commodity derivatives — (21,027 ) (4,191 ) (25,218 ) 7,204 (18,014 ) Interest rate derivatives — (1 ) — (1 ) 1 — LTIP liability — (1,947 ) — (1,947 ) (1,947 ) Noncurrent Commodity derivatives — (1,637 ) (897 ) (2,534 ) 1,460 (1,074 ) Net fair value instruments $ — $ 11,576 $ (5,088 ) $ 6,488 $ — $ 6,488 (a) See Note 12 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 2018 2017 2018 2017 (In thousands) Beginning balance $ 9,909 $ 1,666 $ (5,088 ) $ 8 Total gains (losses) 26,356 (747 ) 40,416 492 Settlements, net (4,649 ) (289 ) (3,712 ) 130 Ending balance $ 31,616 $ 630 $ 31,616 $ 630 Gains (losses) included in earnings relating to derivatives still held as of June 30, 2018 and 2017 $ 23,158 $ (631 ) $ 34,232 $ 89
Nonrecurring 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, 2018 consist of: Fair Value Measurements During the Six Months Ended June 30, 2018 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) $ — $ — $ 26,195 (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, 2018 , Legacy incurred impairment charges of $35.4 million as oil and natural gas properties with a net cost basis of $61.6 million were written down to their fair value of $26.2 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 Instrume27

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
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, 2018 and 2017 : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Beginning fair value of commodity derivatives $ 7,409 $ 43,131 $ 6,318 $ 12,698 Total gain (loss) - oil derivatives (7,082 ) 7,776 (7,824 ) 22,776 Total gain (loss) - natural gas derivatives (2,233 ) 6,740 (3,195 ) 26,409 Crude oil derivative cash settlements paid (received) 6,309 (3,559 ) 11,203 (6,698 ) Natural gas derivative cash settlements received (3,895 ) (3,012 ) (5,994 ) (4,109 ) Ending fair value of commodity derivatives $ 508 $ 51,076 $ 508 $ 51,076
Schedule of notional amounts of outstanding derivative positions	As of June 30, 2018 , 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 2018 1,527,200 $54.76 $51.20 - $63.68 2019 2,190,000 $58.88 $57.15 - $61.20 As of June 30, 2018 , 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 2018 2,024,000 $(1.13) $(1.25) - $(0.80) 2019 730,000 $(1.15) $(1.15) As of June 30, 2018 , 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 2018 782,000 $47.06 $60.29 As of June 30, 2018 , 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 2018 64,400 $57.00 $82.00 $90.50 As of June 30, 2018 , 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 2018 18,160,000 $3.23 $3.04 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39
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, 2018 2017 2018 2017 (In thousands) Beginning fair value of interest rate swaps $ 2,983 $ 1,025 $ 2,117 $ 183 Total gain on interest rate swaps 372 (334 ) 1,315 90 Cash settlements (received) paid (271 ) 249 (348 ) 667 Ending fair value of interest rate swaps $ 3,084 $ 940 $ 3,084 $ 940
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap position as of June 30, 2018 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2018 (Dollars in thousands) $ 235,000 1.363 % 9/1/2015 9/1/2019 $ 3,084

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2018
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, 2018 and year ended December 31, 2017 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 274,686 $ 272,148 Liabilities incurred with properties acquired 156 62 Liabilities incurred with properties drilled 39 39 Liabilities settled during the period (812 ) (1,891 ) Liabilities associated with properties sold (16,107 ) (8,464 ) Current period accretion 6,283 12,792 Asset retirement obligation - end of period $ 264,245 $ 274,686

Partners' Deficit (Tables)

Partners' Deficit (Tables)	6 Months Ended
	Jun. 30, 2018
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 per unit: Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (In thousands) Net income (loss) $ (50,709 ) $ (11,077 ) $ 13,673 $ 5,295 Distributions to preferred unitholders (4,750 ) (4,750 ) (9,500 ) (9,500 ) Net income (loss) attributable to unitholders $ (55,459 ) $ (15,827 ) 4,173 (4,205 ) Weighted average number of units outstanding - basic 76,725 72,354 76,539 72,229 Effect of dilutive securities: Restricted and phantom units — — 894 — Weighted average number of units outstanding - diluted 76,725 72,354 77,433 72,229 Basic & diluted income (loss) per unit $ (0.72 ) $ (0.22 ) $ 0.05 $ (0.06 )

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2018
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, 2018 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2018 722,021 $ 20.13 2.99 $ — Exercised (2,667 ) 4.80 Expired & Forfeited (22,167 ) 28.21 Outstanding at June 30, 2018 697,187 $ 19.93 2.87 $ 225,371 UARs exercisable at June 30, 2018 579,853 $ 22.81 2.60 $ 60,370
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, 2018 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2018 129,499 $ 5.97 Vested (9,988 ) 8.95 Forfeited (2,167 ) 5.66 Non-vested at June 30, 2018 117,344 $ 5.72
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) 2.87 Risk free interest rate 2.6 % Annual distribution rate per unit $0.00 Volatility 91.7 %

Summary of Significant Accoun31

Summary of Significant Accounting Policies - Other Narrative (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Jul. 09, 2018shares	Jun. 22, 2018shares	Mar. 26, 2018shares
Variable Interest Entity [Line Items]
General partner's equity, percent	0.02%	0.02%
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
Shares of aggregate common stock				10,730,000	16,913,592
Asset to liability ratio	1
Subsequent Event | Series A Preferred Stock
Variable Interest Entity [Line Items]
Preferred stock converted to shares of common stock			2.92033118
Subsequent Event | Series B Preferred Stock
Variable Interest Entity [Line Items]
Preferred stock converted to shares of common stock			2.90650421

Summary of Significant Accoun32

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued capital expenditures	$ 58,931	$ 33,198
Accrued lease operating expense	18,493	18,179
Revenue payable to joint interest owners	26,831	18,510
Accrued ad valorem tax	8,956	5,807
Other	5,875	5,624
Accrued oil and natural gas liabilities	$ 119,086	$ 81,318

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted Cash	$ 3.2	$ 3.2	$ 3.2

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt issuance costs, current, net	$ (2,778)	$ 0
Total current debt, net	505,222	0
Long-term debt, gross	817,194	1,369,645
Unamortized discount on Second Lien Term Loans and Senior Notes	(12,228)	(13,101)
Unamortized debt issuance costs	(20,213)	(9,775)
Total long-term debt, net	784,753	1,346,769
Total debt, net	1,289,975	1,346,769
Second Lien Term Loan Due in 2020
Debt Instrument [Line Items]
Long-term debt, gross	338,626	205,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, gross	232,989	232,989
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	245,579	432,656
Credit facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross, current	508,000	0
Long-term debt, gross	$ 0	$ 499,000

Debt - Credit Facility (Details

Debt - Credit Facility (Details)	Apr. 01, 2014USD ($)	Jun. 30, 2018USD ($)	Jul. 01, 2020USD ($)	Oct. 01, 2018	Dec. 31, 2017USD ($)	Oct. 05, 2017USD ($)	Jul. 01, 2017
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 817,194,000			$ 1,369,645,000
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						$ 575,000,000
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							2.50
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
Pro forma total leverage, maximum		3
Long-term debt, gross, current		$ 508,000,000			0
Long-term debt, gross		$ 0			499,000,000
Interest rate at period end		4.76%
Remaining borrowing capacity		$ 66,200,000
Interest paid		$ 12,700,000
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%
Long-term debt, gross		$ 245,579,000			$ 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
Scenario, Forecast | Senior notes
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 15,000,000

Debt - Second Lien Term Loans (

Debt - Second Lien Term Loans (Details)	Jul. 01, 2020USD ($)	Dec. 31, 2018	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 25, 2016USD ($)
Debt Instrument [Line Items]
Long-term debt, gross			$ 817,194,000	$ 1,369,645,000
Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Aggregate principal amount			400,000,000		$ 300,000,000
Long-term debt, upfront fee					2.00%
Stated interest rate					12.00%
Unused borrowing capacity			$ 61,400,000
Debt instrument, asset coverage ratio			0.85
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			0.85
Pro forma total leverage, maximum			3
Scenario, Forecast | Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Ratio of secured debt to EBITDA		4.5
Scenario, Forecast | Senior notes
Debt Instrument [Line Items]
Long-term debt, gross	$ 15,000,000
Subsequent Event | Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Minimum required cash and cash equivalents to secured debt ratio		1

Debt - Senior Notes (Details)

Debt - Senior Notes (Details) - USD ($)	Jun. 01, 2016	May 13, 2014	May 28, 2013	Dec. 04, 2012	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Payments of long-term debt							$ 375,384,000	$ 196,000,000
Gain on extinguishment of debt					$ 0	$ 0	$ 51,693,000	$ 0
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%		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 | 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									$ 187,000,000	$ 117,300,000
Debt extinguished	$ 15,000,000
Payments of long-term debt									$ 132,000,000
Stated interest rate					6.625%		6.625%
Gain on extinguishment of debt							$ 51,700,000
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 | 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						3,800,000

Impact of ASC 606 Adoption (Det

Impact of ASC 606 Adoption (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	$ 139,281	$ 92,847	$ 276,760	$ 192,394
Net income	(50,709)	(11,077)	13,673	5,295
Partners' Capital	(250,985)		(250,985)		$ (271,687)
Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	141,286		280,407
Net income	(50,709)		13,673
Partners' Capital					(271,687)
Oil sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	99,799	46,096	193,210	95,238
Oil sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	99,936		193,379
Natural gas liquids (NGL) sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	5,735	4,921	13,131	9,971
Natural gas liquids (NGL) sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	5,898		13,443
Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	33,747	41,830	70,419	87,185
Natural gas sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	35,452		73,585
Oil and gas
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and natural gas production	49,431	$ 44,802	97,398	$ 96,019
Oil and gas | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and natural gas production	51,436		101,045
Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	(2,005)		(3,647)
Net income	0		0
Partners' Capital					$ 0
Accounting Standards Update 2014-09 | Oil sales | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	(137)		(169)
Accounting Standards Update 2014-09 | Natural gas liquids (NGL) sales | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	(163)		(312)
Accounting Standards Update 2014-09 | Natural gas sales | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue	(1,705)		(3,166)
Accounting Standards Update 2014-09 | Oil and gas | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and natural gas production	$ (2,005)		$ (3,647)

Revenue from Contracts with C39

Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue	$ 139,281	$ 92,847	$ 276,760	$ 192,394
Oil sales
Disaggregation of Revenue [Line Items]
Revenue	99,799	46,096	193,210	95,238
Natural gas liquids (NGL) sales
Disaggregation of Revenue [Line Items]
Revenue	5,735	4,921	13,131	9,971
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenue	$ 33,747	$ 41,830	$ 70,419	$ 87,185

Asset Acquisition and Disposi40

Asset Acquisition and Dispositions (Details) - USD ($) $ in Millions	Aug. 01, 2017	Jun. 30, 2018
Business Acquisition [Line Items]
Proceeds from sale of productive assets		$ 29.2
Gain on disposition of assets		$ 21.5
Jupiter JV, LP
Business Acquisition [Line Items]
Purchase price of acquisition	$ 141

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Board of directors chairman and director | Blue quail energy services, LLC | Water transfer services
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 120,241	$ 9,758

Commitments and Contingencies (

Commitments and Contingencies (Details) - Officer	6 Months Ended
	Jun. 30, 2018
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, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	$ 28,046		$ 28,046		$ 13,424
Fair value of derivatives, asset, noncurrent	9,968		9,968		14,099
Fair value of derivatives, liability, current	27,740		27,740		18,013
Fair value of derivatives, liability, noncurrent	6,682		6,682		1,075
Net fair value instruments	(22,248)		(22,248)		6,488
Gross amount, net	0		0		0
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current					0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Senior notes | 8% Senior Notes due 2020
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Fair value of notes payable	195,100		195,100
Quoted Prices in Active Markets for Identical Assets (Level 1) | Senior notes | 6.625% Senior Notes due 2021
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Fair value of notes payable	196,500		196,500
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current					(1)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current					0
Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value instruments	(22,248)		(22,248)		6,488
Recurring | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	42,837		42,837		19,792
Fair value of derivatives, asset, noncurrent	9,183		9,183		14,278
Fair value of derivatives, liability, current	(44,830)		(44,830)		(25,218)
Fair value of derivatives, liability, noncurrent	(6,682)		(6,682)		(2,534)
Recurring | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	2,300		2,300		837
Fair value of derivatives, asset, noncurrent	784		784		1,281
Fair value of derivatives, liability, current					(1)
Recurring | Long term incentive plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current	(25,840)		(25,840)		(1,947)
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value instruments	0		0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	0		0		0
Fair value of derivatives, asset, noncurrent	0		0		0
Fair value of derivatives, liability, current	0		0		0
Fair value of derivatives, liability, noncurrent	0		0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	0		0		0
Fair value of derivatives, asset, noncurrent	0		0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Long term incentive plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current	0		0		0
Recurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value instruments	(53,864)		(53,864)		11,576
Recurring | Significant Other Observable Inputs (Level 2) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	12,703		12,703		19,792
Fair value of derivatives, asset, noncurrent	7,701		7,701		14,278
Fair value of derivatives, liability, current	(44,830)		(44,830)		(21,027)
Fair value of derivatives, liability, noncurrent	(6,682)		(6,682)		(1,637)
Recurring | Significant Other Observable Inputs (Level 2) | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	2,300		2,300		837
Fair value of derivatives, asset, noncurrent	784		784		1,281
Recurring | Significant Other Observable Inputs (Level 2) | Long term incentive plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current	(25,840)		(25,840)		(1,947)
Recurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value instruments	31,616		31,616		(5,088)
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance	9,909	$ 1,666	(5,088)	$ 8
Total gains (losses)	26,356	(747)	40,416	492
Settlements, net	(4,649)	(289)	(3,712)	130
Ending balance	31,616	630	31,616	630
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Gains (losses) included in earnings relating to derivatives still held as of June 30, 2018 and 2017	23,158	$ (631)	34,232	$ 89
Recurring | Significant Unobservable Inputs (Level 3) | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	30,134		30,134		0
Fair value of derivatives, asset, noncurrent	1,482		1,482		0
Fair value of derivatives, liability, current	0		0		(4,191)
Fair value of derivatives, liability, noncurrent	0		0		(897)
Recurring | Significant Unobservable Inputs (Level 3) | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, asset, current	0		0		0
Fair value of derivatives, asset, noncurrent	0		0		0
Recurring | Significant Unobservable Inputs (Level 3) | Long term incentive plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of derivatives, liability, current	0		0		0
Revolving Credit Facility
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Revolving long-term debt	508,000		508,000
Derivatives Asset Current | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross liability	(12,703)		(12,703)		(7,204)
Derivative asset, net amounts	30,134		30,134		12,588
Derivatives Asset Current | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross liability	0		0		(1)
Derivative asset, net amounts	2,300		2,300		836
Derivatives Asset Noncurrent | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross liability	(4,388)		(4,388)		(1,460)
Derivative asset, net amounts	4,795		4,795		12,818
Derivatives Asset Noncurrent | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, gross liability	0		0
Derivative asset, net amounts	784		784		1,281
Derivatives Liability Current | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability, gross asset	12,703		12,703		7,204
Derivative liability, net amounts	(32,127)		(32,127)		(18,014)
Derivatives Liability Current | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability, gross asset					1
Derivative liability, net amounts					0
Derivatives Liability Current | Long term incentive plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability, gross asset	0		0
Derivative liability, net amounts	(25,840)		(25,840)		(1,947)
Derivatives Liability Noncurrent | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability, gross asset	4,388		4,388		1,460
Derivative liability, net amounts	$ (2,294)		$ (2,294)		$ (1,074)

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements - Nonrecurring (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and natural gas properties using the successful efforts method, at cost	$ 1,371,339		$ 1,371,339		$ 1,353,356
Asset impairment charges	35,381	$ 1,821	35,381	$ 9,883
Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and natural gas properties using the successful efforts method, at cost	0		0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and natural gas properties using the successful efforts method, at cost	0		0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and natural gas properties using the successful efforts method, at cost	$ 26,195		26,195
Net cost basis			61,600
Fair value			26,195
Proved Oil and Gas Properties | Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairment charges			$ 35,400

Derivative Financial Instrume45

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives			$ 0
Total gain (loss) on derivatives			(10,052)	$ 49,942
Derivative cash settlements paid (received)			5,209	(10,807)
Ending fair value of derivatives	$ 0		0
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	7,409	$ 43,131	6,318	12,698
Ending fair value of derivatives	508	51,076	508	51,076
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(7,082)	7,776	(7,824)	22,776
Derivative cash settlements paid (received)	6,309	(3,559)	11,203	(6,698)
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(2,233)	6,740	(3,195)	26,409
Derivative cash settlements paid (received)	$ (3,895)	$ (3,012)	$ (5,994)	$ (4,109)

Derivative Financial Instrume46

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details) MMBTU in Thousands, $ in Thousands	Jun. 30, 2018USD ($)MMBTUbbl$ / MMBTU$ / bbl
NYMEX WTI Swaps | Crude Oil | July-December 2018
Derivative [Line Items]
Volumes | bbl	1,527,200
Average price per Bbl/MMBtu (dollars per bbl/MMBTu	54.76
NYMEX WTI Swaps | Crude Oil | July-December 2018 | Minimum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	51.20
NYMEX WTI Swaps | Crude Oil | July-December 2018 | Maximum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	63.68
NYMEX WTI Swaps | Crude Oil | 2019
Derivative [Line Items]
Volumes | bbl	2,190,000
Average price per Bbl/MMBtu (dollars per bbl/MMBTu	58.88
NYMEX WTI Swaps | Crude Oil | 2019 | Minimum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	57.15
NYMEX WTI Swaps | Crude Oil | 2019 | Maximum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	61.20
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2018
Derivative [Line Items]
Volumes | bbl	2,024,000
Average price per Bbl/MMBtu (dollars per bbl/MMBTu	1.13
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2018 | Minimum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	1.25
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2018 | Maximum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu)	0.80
Midland-to-Cushing Differential Swaps | Crude Oil | 2019
Derivative [Line Items]
Volumes | bbl	730,000
Average price per Bbl/MMBtu (dollars per bbl/MMBTu	1.15
Price range (dollars per bbl/MMBTu)	1.15
NYMEX WTI Crude Oil Costless Collars | Crude Oil | July-December 2018
Derivative [Line Items]
Volumes | bbl	782,000
NYMEX WTI Crude Oil Costless Collars | Crude Oil | July-December 2018 | Long
Derivative [Line Items]
Average long put price for crude oil collar (dollars per bbl)	47.06
NYMEX WTI Crude Oil Costless Collars | Crude Oil | July-December 2018 | Short
Derivative [Line Items]
Average short call price for crude oil collar (dollars per bbl)	60.29
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2018
Derivative [Line Items]
Volumes | bbl	64,400
Average price per Bbl/MMBtu (dollars per bbl/MMBTu	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2018 | Long
Derivative [Line Items]
Average strike price (dollars per bbl)	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | July-December 2018 | Short
Derivative [Line Items]
Average strike price (dollars per bbl)	82
NYMEX Henry Hub Natural Gas Swaps | Natural gas | July-December 2018
Derivative [Line Items]
Volumes | MMBTU	18,160
Average price per Bbl/MMBtu (dollars per bbl/MMBTu | $ / MMBTU	3.23
NYMEX Henry Hub Natural Gas Swaps | Natural gas | July-December 2018 | Minimum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu) | $ / MMBTU	3.04
NYMEX Henry Hub Natural Gas Swaps | Natural gas | July-December 2018 | Maximum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu) | $ / MMBTU	3.39
NYMEX Henry Hub Natural Gas Swaps | Natural gas | 2019
Derivative [Line Items]
Volumes | MMBTU	25,800
Average price per Bbl/MMBtu (dollars per bbl/MMBTu | $ / MMBTU	3.36
NYMEX Henry Hub Natural Gas Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu) | $ / MMBTU	3.29
NYMEX Henry Hub Natural Gas Swaps | Natural gas | 2019 | Maximum
Derivative [Line Items]
Price range (dollars per bbl/MMBTu) | $ / MMBTU	3.39
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 | $	$ 3,084

Derivative Financial Instrume47

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives			$ 0
Cash settlements (received) paid			5,209	$ (10,807)
Ending fair value of derivatives	$ 0		0
Interest rate swaps | Not designated as hedging instrument
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	2,983	$ 1,025	2,117	183
Cash settlements (received) paid	(271)	249	(348)	667
Ending fair value of derivatives	3,084	940	3,084	940
Interest rate swaps | Not designated as hedging instrument | Interest expense
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain on interest rate swaps	$ 372	$ (334)	$ 1,315	$ 90

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Changes in the ARO
Asset retirement obligation - beginning of period	$ 274,686	$ 272,148
Liabilities incurred with properties acquired	156	62
Liabilities incurred with properties drilled	39	39
Liabilities settled during the period	(812)	(1,891)
Liabilities associated with properties sold	(16,107)	(8,464)
Current period accretion	6,283	12,792
Asset retirement obligation - end of period	$ 264,245	$ 274,686

Partners' Deficit - Preferred U

Partners' Deficit - Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2018	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)	$ 4.92
Distributions in arrears	$ 46.7
Series A Preferred Equity
Class of Stock [Line Items]
Preferred equity, units outstanding (in shares)	2,300,000
Dividend rate	8.00%
Series A Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate	5.24%
Series B Preferred Equity
Class of Stock [Line Items]
Preferred equity, units outstanding (in shares)	7,200,000
Dividend rate	8.00%
Series B Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate	5.256%
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, 2014$ / sharesshares	Jun. 30, 2018
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
Unvested IDUs
Class of Stock [Line Items]
Equity interests issuable (in shares)	200,000
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, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Equity [Abstract]
Net income	$ (50,709)	$ (11,077)	$ 13,673	$ 5,295
Distributions to preferred unitholders	(4,750)	(4,750)	(9,500)	(9,500)
Net income (loss) attributable to unitholders	$ (55,459)	$ (15,827)	$ 4,173	$ (4,205)
Weighted average number of units outstanding (in shares)	76,725,000	72,354,000	76,539,000	72,229,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	894,000	0
Weighted average units and potential units outstanding (in shares)	76,725,000	72,354,000	77,433,000	72,229,000
Income (loss) per unit - basic and diluted (in dollars per share)	$ (0.72)	$ (0.22)	$ 0.05	$ (0.06)
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)	135,089	324,604	57,625
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)	1,424,114		607,488	1,389,773

Unit-Based Compensation - LTIP,

Unit-Based Compensation - LTIP, Unit Appreciation Rights and Unit Options (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Jun. 12, 2015	Jun. 11, 2015
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	$ 400,000	$ 1,000,000
Unrecognized compensation costs	$ 400,000
Unrecognized compensation costs, weighted-average remaining period for recognition	1 year 7 months 30 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	$ 23,200,000	$ 1,900,000
Unrecognized compensation costs	38,600,000
Unrecognized compensation costs, weighted-average remaining period for recognition		2 years 2 months 30 days
Unit appreciation rights (UARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense (benefit)	1,500,000	$ (100,000)
Unrecognized compensation costs	$ 100,000
Unrecognized compensation costs, weighted-average remaining period for recognition	2 months 20 days
Volatility	91.70%
Share based compensation, forfeiture rate	5.60%
Annual distribution	$ 0
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)	3,459,197
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)	988,207
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)	1,424,114
Long term incentive plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	780,862

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, 2018	Dec. 31, 2017
Units (in shares)
Outstanding, beginning balance (in units)	722,021
Exercised (in units)	(2,667)
Expired (in units)	(22,167)
Outstanding, ending balance (in units)	697,187	722,021
UARs exercisable (in units)	579,853
Weighted-Average Exercise Price (in dollars per share)
Outstanding, beginning balance (in dollars per share)	$ 20.13
Exercised (in dollars per share)	4.80
Expired and forfeited (in dollars per share)	28.21
Outstanding, ending balance (in dollars per share)	19.93	$ 20.13
UARs exercisable (in dollars per share)	$ 22.81
Weighted-Average Remaining Contractual Term
Outstanding	2 years 10 months 12 days	2 years 11 months 27 days
UARs exercisable	2 years 7 months 7 days
Aggregate Intrinsic Value
Outstanding	$ 225,371	$ 0
UARs exercisable	$ 60,370

Unit-Based Compensation - Statu

Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details)	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Number of Units
Vested (in units)	0
Unit appreciation rights (UARs)
Number of Units
Non-vested, beginning balance (in units)	129,499
Vested (in units)	(9,988)
Forfeited (in units)	(2,167)
Non-vested, ending balance (in units)	117,344
Weighted- Average Exercise Price
Non-vested, beginning balance (in dollars per unit) | $ / shares	$ 5.97
Vested (in dollars per unit) | $ / shares	8.95
Forfeited (in dollars per unit) | $ / shares	5.66
Non-vested, ending balance (in dollars per unit) | $ / shares	$ 5.72

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	2.60%
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	2 years 10 months 12 days	2 years 11 months 27 days
Risk free interest rate	2.60%
Annual distribution rate per unit (in dollars per share)	$ 0
Volatility	91.70%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details) $ / shares in Units, $ in Millions	May 15, 2018director$ / sharesshares	Feb. 16, 2018$ / sharesshares	May 16, 2017director$ / sharesshares	Feb. 21, 2017$ / sharesshares	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Partnership unit conversion ratio					1
Share-based compensation expense | $					$ 23.2	$ 1.9
Unrecognized compensation costs | $					38.6
Unrecognized compensation costs, period of recognition						2 years 2 months 30 days
Subjective or service based phantom units | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value (in dollars per share) | $ / shares		$ 3.69		$ 2.25
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense | $					0.4	$ 1
Unrecognized compensation costs | $					$ 0.4
Unrecognized compensation costs, period of recognition					1 year 7 months 30 days
Unvested units not included in consolidated balance sheet (in shares)					135,089
Unrestricted units | Director 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	6,010
Individuals eligible for plan | director	2
Unrestricted units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	12,019		47,847
Individuals eligible for plan | director	4		6
Value of each unit at issuance (in dollars per share) | $ / shares	$ 8.69		$ 2.04
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
Maximum | Subjective or service based phantom units | Director 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		635,590
Maximum | Subjective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				793,701
Maximum | Subjective phantom share units (PSUs) | Director 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		317,794
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
Maximum | Objective phantom share units (PSUs) | Director 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		3,813,536

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - Senior notes	11 Months Ended
	May 08, 2014offering	Jun. 30, 2018	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 Narrative (De

Subsequent Events Narrative (Details) - shares	Jul. 09, 2018	Jun. 22, 2018	Mar. 26, 2018
Subsequent Event [Line Items]
Shares of aggregate common stock		10,730,000	16,913,592
Series A Preferred Stock | Subsequent Event
Subsequent Event [Line Items]
Preferred stock converted to shares of common stock	2.92033118
Series B Preferred Stock | Subsequent Event
Subsequent Event [Line Items]
Preferred stock converted to shares of common stock	2.90650421