Legacy Reserves 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	LEGACY RESERVES LP
Entity Central Index Key	1,358,831
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		69,500,408
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 506.4

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash	$ 2,006	$ 725
Accounts receivable, net:
Oil and natural gas	33,944	49,390
Joint interest owners	25,378	16,235
Other	86	237
Fair value of derivatives	63,711	120,305
Prepaid expenses and other current assets	4,334	5,362
Total current assets	129,459	192,254
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting	3,485,634	2,946,820
Unproved properties	13,424	47,613
Accumulated depletion, depreciation, amortization and impairment	(2,090,102)	(1,354,459)
Total oil and natural gas assets	1,408,956	1,639,974
Other property and equipment, net of accumulated depreciation and amortization of $8,915 and $7,446, respectively	4,575	3,767
Operating rights, net of amortization of $4,953 and $4,509, respectively	2,064	2,508
Fair value of derivatives	56,373	32,794
Other assets, net of amortization of $15,563 and $12,551, respectively	23,829	24,255
Investments in equity method investees	646	3,054
Total assets	1,625,902	1,898,606
Current liabilities:
Accounts payable	13,581	2,787
Accrued oil and natural gas liabilities	50,573	78,615
Fair value of derivatives	2,019	2,080
Asset retirement obligation	3,496	3,028
Other	11,424	11,066
Total current liabilities	81,093	97,576
Long-term debt	1,440,396	938,876
Asset retirement obligation	282,909	223,497
Fair value of derivatives	0	0
Other long-term liabilities	1,181	1,452
Total liabilities	$ 1,805,579	$ 1,261,401
Commitments and contingencies
Partners’ equity (deficit):
Limited partners' equity (deficit) - 68,949,961 and 68,910,784 units issued and outstanding at December 31, 2015 and 2014, respectively	$ (439,811)	$ 376,885
General partner’s equity (deficit) (approximately 0.03%)	(133)	53
Total partners’ equity (deficit)	(179,677)	637,205
Total liabilities and partners’ equity	1,625,902	1,898,606
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2015 and December 31, 2014
Partners’ equity (deficit):
Incentive distribution equity	30,814	30,814
Total partners’ equity (deficit)	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2015 and December 31, 2014
Partners’ equity (deficit):
Preferred equity	55,192	55,192
Total partners’ equity (deficit)	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2015 and December 31, 2014
Partners’ equity (deficit):
Preferred equity	174,261	174,261
Total partners’ equity (deficit)	$ 174,261	$ 174,261

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Other property and equipment, accumulated depreciation and amortization	$ 8,915	$ 7,446
Operating rights, amortization	4,953	4,509
Other assets, amortization	$ 15,563	$ 12,551
Limited partners' equity, units issued (in shares)	68,949,961	68,910,784
Limited partners' equity, units outstanding (in shares)	68,949,961	68,910,784
General partner's equity, percent	0.03%	0.03%
Incentive Distribution Equity
Incentive distribution equity, units issued (in shares)	100,000	100,000
Incentive distribution equity, units outstanding (in shares)	100,000	100,000
Series A Preferred Equity
Preferred equity, units issued (in shares)	2,300,000	2,300,000
Preferred equity, units outstanding (in shares)	2,300,000	2,300,000
Series B Preferred Equity
Preferred equity, units issued (in shares)	7,200,000	7,200,000
Preferred equity, units outstanding (in shares)	7,200,000	7,200,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil sales	$ 199,841	$ 396,774	$ 405,536
Natural gas liquids (NGL) sales	16,645	27,483	14,095
Natural gas sales	122,293	108,042	65,858
Total revenues	338,779	532,299	485,489
Expenses:
Oil and natural gas production	194,491	198,801	154,679
Production and other taxes	16,383	31,534	29,508
General and administrative	46,511	38,980	28,907
Depletion, depreciation, amortization and accretion	177,258	173,686	158,415
Impairment of long-lived assets	633,805	448,714	85,757
(Gain) loss on disposal of assets	(3,972)	(2,479)	579
Total expenses	1,064,476	889,236	457,845
Operating income (loss)	(725,697)	(356,937)	27,644
Other income (expense):
Interest income	329	873	776
Interest expense	(76,891)	(67,218)	(50,089)
Equity in income of equity method investees	126	428	559
Net gains (losses) on commodity derivatives	98,253	138,092	(13,531)
Other	841	258	18
Loss before income taxes	(703,039)	(284,504)	(34,623)
Income tax (expense) benefit	1,498	859	(649)
Net loss	(701,541)	(283,645)	(35,272)
Distributions to preferred unitholders	(19,000)	(11,694)	0
Net loss attributable to unitholders	$ (720,541)	$ (295,339)	$ (35,272)
Income (loss) per unit — basic and diluted (in dollars per share)	$ (10.45)	$ (4.92)	$ (0.62)
Weighted average number of units used in computing net loss per unit —
Basic (in shares)	68,928	60,053	57,220
Diluted (in shares)	68,928	60,053	57,220

Consolidated Statements of Unit

Consolidated Statements of Unitholders Equity - USD ($) shares in Thousands, $ in Thousands	Total	Non-employee directors	Incentive Distribution Equity	Preferred Units	Series A Preferred Equity	Series B Preferred Equity	Limited Partner	Limited PartnerNon-employee directors	General Partner
Unitholders equity, beginning balance (in shares) at Dec. 31, 2012			0		0	0	57,039
Unitholders equity, beginning balance at Dec. 31, 2012	$ 670,280		$ 0		$ 0	$ 0	$ 670,183		$ 97
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued to for services (in shares)								18
Units issued for services	3,582	$ 509					$ 3,582	$ 509
Vesting of restricted and phantom units (in shares)							70
Offering costs associated with the issuance of units	(25)						$ (25)
Units issued in exchange for oil and natural gas properties and investment in equity method investee (in shares)							153
Units issued in exchange for oil and natural gas properties and investment in equity method investee	4,001						$ 4,001
Redemption of general partner interest	(12)								(12)
Distributions to unitholders, $2.31, $2.405 and $1.46 per unit for the years ended December 31, 2013, 2014, and 2015, respectively	(132,667)						(132,667)
Net loss	(35,272)						$ (35,261)		(11)
Unitholders equity, ending balance (in shares) at Dec. 31, 2013			0		0	0	57,280
Unitholders equity, ending balance at Dec. 31, 2013	510,396		$ 0		$ 0	$ 0	$ 510,322		74
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued to for services (in shares)					2,300	7,200		18
Units issued for services	3,797	499		$ 229,453	$ 55,192	$ 174,261	$ 3,797	$ 499
Vesting of restricted and phantom units (in shares)							113
Net proceeds from equity offering / Issuance of units, net (in shares)							11,500
Net proceeds from equity offering / Issuance of units, net	303,457						$ 303,457
Units issued in exchange for oil and natural gas properties and investment in equity method investee (in shares)			100
Units issued in exchange for oil and natural gas properties and investment in equity method investee	30,814		$ 30,814
Distributions to preferred unitholders	(11,694)						(11,694)
Distributions to unitholders, $2.31, $2.405 and $1.46 per unit for the years ended December 31, 2013, 2014, and 2015, respectively	(145,872)						(145,872)
Net loss	(283,645)						$ (283,624)		(21)
Unitholders equity, ending balance (in shares) at Dec. 31, 2014			100		2,300	7,200	68,911
Unitholders equity, ending balance at Dec. 31, 2014	637,205		$ 30,814		$ 55,192	$ 174,261	$ 376,885		53
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued to for services (in shares)								66
Units issued for services	5,858	$ 604					$ 5,858	$ 604
Vesting of restricted and phantom units (in shares)							78
Offering costs associated with the issuance of units	(103)						$ (103)
Units issued in exchange for oil and natural gas properties and investment in equity method investee (in shares)							(105)
Units issued in exchange for oil and natural gas properties and investment in equity method investee	(1,349)						$ (1,349)
Distributions to preferred unitholders	(19,000)						(19,000)
Distributions to unitholders, $2.31, $2.405 and $1.46 per unit for the years ended December 31, 2013, 2014, and 2015, respectively	(101,351)						(101,351)
Net loss	(701,541)						$ (701,355)		(186)
Unitholders equity, ending balance (in shares) at Dec. 31, 2015			100		2,300	7,200	68,950
Unitholders equity, ending balance at Dec. 31, 2015	$ (179,677)		$ 30,814		$ 55,192	$ 174,261	$ (439,811)		$ (133)

Consolidated Statements of Uni6

Consolidated Statements of Unitholders Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Partners' Capital [Abstract]
Distributions to unitholders (in dollars per share)	$ 1.46	$ 2.405	$ 2.31

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net loss	$ (701,541)	$ (283,645)	$ (35,272)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	177,258	173,686	158,415
Amortization of debt discount and issuance costs	5,532	4,637	3,780
Impairment of long-lived assets	633,805	448,714	85,757
(Gains) losses on derivatives	(99,971)	(140,771)	8,743
Equity in income of equity method investees	(126)	(428)	(559)
Distribution from equity method investee	191	1,467	861
Unit-based compensation	6,451	2,089	3,142
(Gain) loss on disposal of assets	(3,972)	(2,479)	579
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	15,447	(1,962)	(9,882)
(Increase) decrease in accounts receivable, joint interest owners	(9,143)	297	11,319
(Increase) decrease in accounts receivable, other	151	389	(75)
(Increase) decrease in other assets	333	(1,193)	618
Increase (decrease) in accounts payable	10,794	(3,228)	4,194
Increase (decrease) in accrued oil and natural gas liabilities	(28,042)	15,454	12,999
Decrease in other liabilities	(5,121)	(5,811)	(3,485)
Total adjustments	703,587	490,861	276,406
Net cash provided by operating activities	2,046	207,216	241,134
Cash flows from investing activities:
Investment in oil and natural gas properties	(577,186)	(638,942)	(202,419)
Proceeds from sale of assets	69,118	5,334	2,566
Investment in other equipment	(2,277)	(1,472)	(2,492)
Net cash settlements on commodity derivatives	132,925	2,666	(7,056)
Net cash used in investing activities	(377,420)	(632,414)	(209,401)
Cash flows from financing activities:
Proceeds from long-term debt	840,000	1,333,000	802,263
Payments of long-term debt	(341,000)	(1,275,000)	(701,000)
Payments of debt issuance costs	(1,891)	(10,005)	(1,217)
Proceeds from issuance of limited partner interests, net	(103)	532,910	(25)
Redemption of general partner interest	0	0	(12)
Distributions to unitholders	(120,351)	(157,566)	(132,667)
Net cash provided by (used in) financing activities	376,655	423,339	(32,658)
Net increase (decrease) in cash	1,281	(1,859)	(925)
Cash, beginning of period	725	2,584	3,509
Cash, end of period	2,006	725	2,584
Non-Cash Investing and Financing Activities:
Asset retirement obligation costs and liabilities	92	941	494
Asset retirement obligations associated with property acquisitions	60,526	50,487	10,969
Asset retirement obligations associated with properties sold	(9,386)	(5,891)	(1,606)
Units issued (acquired) in exchange for investment in equity method investee	(1,349)	0	4,001
Incentive Distribution units issued in exchange for oil and natural gas properties	0	30,814	0
Note receivable received in exchange for the sale of oil and natural gas properties	$ 0	$ 0	$ 11,857

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies (a) Organization, Basis of Presentation and Description of Business Legacy Reserves LP (“LRLP,” “Legacy” or the “Partnership”) and its affiliated entities are referred to as Legacy in these financial statements. 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 it currently owns an approximately 0.03% general partner interest in LRLP. Significant information regarding rights of the unitholders includes the following: • Right to receive distributions of available cash within 45 days after the end of each quarter. • No limited partner shall have any management power over our 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 LRLP’s general partner and its affiliates. • Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year. In the event of a 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 LRLP’s general partner 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 East Texas, the Permian Basin (West Texas and Southeast New Mexico), Rocky Mountain and Mid-Continent regions of the United States. Legacy has acquired oil and natural gas producing properties and drilled and undrilled leasehold. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. (b) Accounts Receivable Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10). (c) Oil and Natural Gas Properties Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties 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 Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2015 , Legacy recognized $633.8 million of impairment expense, $598.1 million of of which was in 218 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2015 , which decreased the expected future cash flows below the carrying value of the assets. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2014 , Legacy recognized $448.7 million of impairment expense, $413.3 million of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014 , which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2013 , Legacy recognized $78.0 million of impairment expense on 98 separate producing fields, due primarily to the decrease in commodity prices primarily related to natural gas differentials during the year ended December 31, 2013 , combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. During the years ended December 31, 2015 , 2014 and 2013 , Legacy recognized $35.7 million , $35.0 million and $7.8 million of impairment of unproven properties, respectively. (d) Oil, NGLs and Natural Gas Reserve Quantities Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered. (e) Income Taxes Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. Legacy recorded income tax (expense) benefit of $1.5 million , $0.9 million and $(0.6) million for the years ended December 31, 2015 , 2014 and 2013 , respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.4 billion at December 31, 2015 . (f) Derivative Instruments and Hedging Activities Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9). (g) Use of Estimates Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. (h) Revenue Recognition Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments 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. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. 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 recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. Legacy uses the “net-back” method of accounting for transportation arrangements of its natural gas sales. Legacy sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its purchasers and reflected in the wellhead price. Legacy’s contracts with respect to the sale of its natural gas produced, with one immaterial exception, provide Legacy with a net price payment. That is, when Legacy is paid for its natural gas by its purchasers, Legacy receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of Legacy’s contracts, the payment statements Legacy receives from its purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, Legacy’s revenues are recorded at this single net price. 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, 2015 , 2014 and 2013 . Legacy is paid a monthly operating fee for each well it operates for outside owners proportionate to each owner's working interest. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense. (i) Investments Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition. (j) Intangible assets Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life. The expected amortization expenses for 2016, 2017, 2018, 2019 and 2020 are $417,000 , $396,000 , $358,000 , $349,000 and $322,000 , respectively. (k) Environmental Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. (l) Income (Loss) Per Unit Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12). (m) Redemption of Units Units redeemed are recorded at cost. (n) Segment Reporting Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes. (o) Unit-Based Compensation Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2015 , do not include 550,447 units related to unvested restricted unit awards. (p) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of December 31, 2015 and 2014 . December 31, 2015 2014 (In thousands) Revenue payable to joint interest owners $ 15,253 $ 19,267 Accrued lease operating expense 19,007 21,177 Accrued capital expenditures 2,881 20,773 Accrued ad valorem tax 8,723 9,382 Other 4,709 8,016 $ 50,573 $ 78,615

Fair Values of Financial Instru

Fair Values of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Values of Financial Instruments	Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts except as discussed below: Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $84.0 million and $165.6 million , respectively, as of December 31, 2015 . As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. 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. As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 : Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Total Carrying Description (Level 1) (Level 2) (Level 3) Value as of (In thousands) LTIP liability(a) $ — $ — $ — $ — Oil and natural gas derivatives — 122,920 (4,493 ) 118,427 Interest rate swaps — (362 ) — (362 ) Total as of December 31, 2015 $ — $ 122,558 $ (4,493 ) $ 118,065 LTIP liability(a) $ — $ (11 ) $ — $ (11 ) Oil and natural gas derivatives — 152,544 555 153,099 Interest rate swaps — (2,080 ) — (2,080 ) Total as of December 31, 2014 $ — $ 150,453 $ 555 $ 151,008 ____________________ (a) See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our 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 such 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) December 31, 2015 2014 2013 (In thousands) Beginning balance $ 555 $ 20,615 $ 29,966 Total gains (losses) (10,029 ) (6,185 ) 4,671 Settlements 4,981 677 (6,722 ) Transfers — (14,552 ) (a) (7,300 ) (b) Ending balance $ (4,493 ) $ 555 $ 20,615 Gains included in earnings relating to derivatives still held as of December 31, 2015, 2014 and 2013 $ (4,493 ) $ 555 $ 1,407 (a) During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. (b) During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2. 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 Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("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 measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2015 and 2014 consist of: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description (Level 1) (Level 2) (Level 3) (In thousands) 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 2014 Impairment(a) $ — $ — $ 254,266 Acquisitions(b) $ — $ — $ 536,334 ____________________ (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 year ended December 31, 2015 , Legacy incurred impairment charges of $598.1 million as oil and natural gas properties with a net cost basis of $983.6 million were written down to their fair value of $385.5 million . During the year ended December 31, 2014 , Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 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 remaining $35.7 million of impairment during the year ended December 31, 2015 represented impairment of unproved properties acquired since 2010 that are no longer viable. The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that were no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2015 , Legacy acquired oil and natural gas properties with a fair value of $540.3 million in the Anadarko Acquisitions and 3 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2014 , Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following at December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Credit Facility due 2019 $ 608,000 109,000 8% Senior Notes due 2020 300,000 300,000 6.625% Senior Notes due 2021 550,000 550,000 1,458,000 959,000 Unamortized discount on Senior Notes (17,604 ) (20,124 ) Total long term debt $ 1,440,396 $ 938,876 Credit Facility Previous Credit Agreement: On March 10, 2011, Legacy entered into a five -year $1 billion secured revolving credit facility (as amended, the "Previous Credit Agreement"). Borrowings under the Previous Credit Agreement were set to mature on March 10, 2016. Current Credit Agreement: On April 1, 2014, Legacy entered into a five -year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, as amended through the Seventh Amendment, (the "Current Credit Agreement") which replaced the Previous Credit Agreement. Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 90% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the lesser of the borrowing base and the facility amount and contains a $2 million sub-limit for letters of credit. The borrowing base at December 31, 2015 was set at $900 million , but was reduced to $725 million on February 19, 2016 pursuant to the Seventh Amendment to the revolving credit facility. Please see Note 15, Subsequent Events for more details. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year. Any borrowings in excess of the redetermined borrowing base must be repaid. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.5% to 2.5% , or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00% , plus an applicable margin from 0.5% to 1.5% per annum, determined by the percentage of the borrowing base then in effect that is drawn. The Current Credit Agreement contains various covenants that limit Legacy's ability to: (i) incur indebtedness, (ii) enter into certain leases, (iii) grant certain liens, (iv) enter into certain swaps, (v) make certain loans, acquisitions, capital expenditures and investments, (vi) make distributions other than from available cash, (vii) merge, consolidate or allow any material change in the character of its business and (viii) engage in certain asset dispositions, including a sale of all or substantially all of its assets. The Current Credit Agreement also contains covenants that, among other things, require Legacy to maintain specified ratios or conditions. As of December 31, 2015 these covenants were as follows: (i) secured debt at any time to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter preceding such day of not more than 2.5 to 1.0, (ii) as of the last day of the most recent quarter, total EBITDA over the last four quarters to total interest expense over the last four quarters to be greater than 2.5 to 1.0 and (iii) consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives. As of December 31, 2015 , Legacy had outstanding borrowings of $608 million under the Current Credit Agreement at a weighted average interest rate of 2.40% . Thus, Legacy had approximately $291.6 million of borrowing availability remaining. As of February 23, 2016, Legacy had approximately $105.6 million of borrowing availability remaining as a result of the borrowing base reduction to $725 million in accordance with the Seventh Amendment to the revolving credit facility. For the year ended December 31, 2015 , Legacy paid $9.4 million of interest expense on the Current Credit Agreement, $24.0 million on the 2020 Senior Notes and $36.4 million on the 2021 Senior Notes. At December 31, 2015 , Legacy was in compliance with all covenants contained in the Current Credit Agreement. Depending on oil and natural gas prices in 2016, we could breach certain financial covenants under our revolving credit facility, which would constitute a default under our revolving credit facility. Such default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our revolving credit facility or foreclosure on our oil and natural gas properties. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to date, which include the suspension of distributions to our unitholders and Preferred Unitholders, as well as asset sales completed and anticipated as of the date of this filing, will be viewed positively by our lenders. A default under Legacy's revolving credit facility could cause all of Legacy's existing indebtedness, including Legacy's 2020 Senior Notes and 2021 Senior Notes, to be immediately due and payable. 8% Senior Notes Due 2020 On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 8% Senior Notes due 2020 (the "2020 Senior Notes"), which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. Year Percentage 2016 104.000 % 2017 102.000 % 2018 100.000 % Prior to December 1, 2016, Legacy may redeem all or any part of the 2020 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to December 1, 2015, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes at the redemption price of 108% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy 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, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 14 - Subsidiary Guarantors for further details on Legacy's guarantors. The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. Further, 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. The indenture also includes customary events of default. As of the December 31, 2015 , The Partnership was in compliance with all covenants of the 2020 Senior Notes. Interest is payable on June 1 and December 1 of each year. 6.625% Senior Notes Due 2021 On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes"), which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 6.625% 2021 Senior Notes. These 2021 Senior Notes were issued at 99% of par. The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the maturity date, interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. Year Percentage 2017 103.313 % 2018 101.656 % 2019 and thereafter 100.000 % Prior to June 1, 2017, Legacy may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to June 1, 2016, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at the redemption price of 106.625% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2021 Senior Notes are guaranteed by the same parties and on the same terms as Legacy's 2020 Senior Notes discussed above. Further, 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. As of December 31, 2015 , the Partnership was in compliance with all covenants of the 2021 Senior Notes. Interest is payable on June 1 and December 1 of each year.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions WPX Acquisition On June 4, 2014, Legacy purchased a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy Rocky Mountain, LLC , a subsidiary of WPX Energy, Inc., (the "WPX Acquisition") for a net purchase price of $360.0 million . Consideration included both cash and 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units"), 100,000 of which vested immediately and the remainder of which are available to vest and also subject to forfeiture pursuant to the terms of a related Incentive Distribution Units Holders Agreement. This acquisition was accounted for as a business combination. The 100,000 vested Incentive Distribution Units have been reflected in the financial statements at their estimated issuance date fair value of $30.8 million . No value was ascribed to the unvested Incentive Distribution Units upon the closing of the WPX Acquisition as the vesting of the unvested Incentive Distribution Units is dependent upon the consummation of future transactions with WPX and such Incentive Distribution Units will be a portion of the consideration of any such future transactions. During the year ended December 31, 2014, Legacy incurred acquisition costs, recorded in general and administrative expense, of approximately $5.4 million related to the WPX Acquisition and other acquisitions. The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 422,739 Future abandonment costs (62,748 ) Fair value of net assets acquired $ 359,991 Anadarko Acquisitions On July 31, 2015, Legacy purchased (1) 100% of the issued and outstanding limited liability company membership interests in Dew Gathering LLC, which owns directly and indirectly natural gas gathering and processing assets in Anderson, Freestone, Houston, Leon, Limestone and Robertson Counties, Texas (the "WGR Acquisition") from WGR Operating LP ("WGR") for a net purchase price of $96.7 million , and (2) various oil and natural gas properties and associated production assets (the "Anadarko E&P Acquisition," together with the WGR Acquisition, the "Anadarko Acquisitions") from Anadarko E&P Onshore LLC ("Anadarko") for a net purchase price of $335.5 million . The purchase prices were financed with borrowings under Legacy’s revolving credit facility. The effective date of these purchases was April 1, 2015. The operating results from the Anadarko Acquisitions have been included from their acquisition on July 31, 2015. During the year ended December 31, 2015, Legacy incurred acquisition costs, recorded in general and administrative expense, of approximately $2.4 million related to the Anadarko Acquisitions and other acquisitions. The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 459,540 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 432,189 Pro Forma Operating Results The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013 and the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future: Year Ended December 31, 2015 2014 2013 (In thousands) Revenues $ 380,619 $ 687,829 $ 549,968 Net loss $ (713,364 ) $ (243,197 ) $ (50,041 ) Loss per unit — basic and diluted $ (10.35 ) $ (4.05 ) $ (0.87 ) Units used in computing loss per unit: Basic 68,928 60,053 57,220 Diluted 68,928 60,053 57,220 The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the WPX Acquisition and the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. Year Ended December 31, 2015 2014 2013 WPX Acquisition (In thousands) Revenues $ 69,504 $ 48,470 $ — Excess of revenues over direct operating expenses $ 22,324 $ 22,333 $ — Anadarko Acquisitions Revenues $ 22,881 $ — $ — Excess of revenues over direct operating expenses $ 12,373 $ — $ —

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown, Legacy's Chairman and Dale A. Brown, a director of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and in 2015 paid $382,629 to Blue Quail for such services. Cary D. Brown and Kyle A. McGraw, Director and Legacy’s Executive Vice President and Chief Development Officer, own interests in partnerships which, in turn, own a combined non-controlling 4.16% interest as limited partners in a partnership which, until November 10, 2014, owned the building that Legacy occupies. Monthly rent is $102,465 without respect to property taxes and insurance. The lease expires in September 2020. In mid-2015 Legacy performed a technical evaluation of a potential acquisition and, based on such evaluation and Legacy’s business model, subsequently decided not to pursue such acquisition. In September 2015, Moriah Powder River LLC, an oil and natural gas exploration and production company which Cary D. Brown and Dale Brown indirectly control, decided to pursue such opportunity and paid Legacy a one-time expense reimbursement of $500,000 to utilize Legacy's prior technical work product.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy is party to a contractual agreement, extending through 2022, to purchase CO 2 volumes from a third party. The contract requires Legacy to purchase minimum annual volumes, the pricing of which is calculated as a percentage of NYMEX-WTI oil prices, with a floor of $57.14 . Based upon the minimum required volumes and the NYMEX-WTI strip prices as of December 31, 2015 , we estimate the value of our total future obligation to be approximately $49.8 million . Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected. Legacy has employment agreements with its officers that specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively.

Business and Credit Concentrati

Business and Credit Concentrations	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Business and Credit Concentrations	Business and Credit Concentrations Cash Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. Revenue and Accounts Receivable Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2015 , 2014 or 2013 . Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. Commodity Derivatives Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or three-way 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. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2015 , Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $118.4 million , collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. Sales to Major Customers For the year ended December 31, 2015 , Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the years ended December 31, 2014 and 2013 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2015 2014 2013 Enterprise (Teppco) Crude Oil, LP 6% 12% 17% Plains Marketing, LP 7% 10% 7% In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Legacy believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts except as discussed below: Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $84.0 million and $165.6 million , respectively, as of December 31, 2015 . As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. 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. As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 : Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Total Carrying Description (Level 1) (Level 2) (Level 3) Value as of (In thousands) LTIP liability(a) $ — $ — $ — $ — Oil and natural gas derivatives — 122,920 (4,493 ) 118,427 Interest rate swaps — (362 ) — (362 ) Total as of December 31, 2015 $ — $ 122,558 $ (4,493 ) $ 118,065 LTIP liability(a) $ — $ (11 ) $ — $ (11 ) Oil and natural gas derivatives — 152,544 555 153,099 Interest rate swaps — (2,080 ) — (2,080 ) Total as of December 31, 2014 $ — $ 150,453 $ 555 $ 151,008 ____________________ (a) See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our 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 such 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) December 31, 2015 2014 2013 (In thousands) Beginning balance $ 555 $ 20,615 $ 29,966 Total gains (losses) (10,029 ) (6,185 ) 4,671 Settlements 4,981 677 (6,722 ) Transfers — (14,552 ) (a) (7,300 ) (b) Ending balance $ (4,493 ) $ 555 $ 20,615 Gains included in earnings relating to derivatives still held as of December 31, 2015, 2014 and 2013 $ (4,493 ) $ 555 $ 1,407 (a) During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. (b) During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2. 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 Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("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 measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2015 and 2014 consist of: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description (Level 1) (Level 2) (Level 3) (In thousands) 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 2014 Impairment(a) $ — $ — $ 254,266 Acquisitions(b) $ — $ — $ 536,334 ____________________ (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 year ended December 31, 2015 , Legacy incurred impairment charges of $598.1 million as oil and natural gas properties with a net cost basis of $983.6 million were written down to their fair value of $385.5 million . During the year ended December 31, 2014 , Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 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 remaining $35.7 million of impairment during the year ended December 31, 2015 represented impairment of unproved properties acquired since 2010 that are no longer viable. The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that were no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2015 , Legacy acquired oil and natural gas properties with a fair value of $540.3 million in the Anadarko Acquisitions and 3 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2014 , Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Commodity derivative transactions Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes. These derivative instruments are intended to mitigate a portion of 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, who currently are all 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 years ended December 31, 2015 , 2014 , and 2013 . December 31, 2015 2014 2013 (In thousands) Beginning fair value of commodity derivatives $ 153,099 $ 17,673 $ 24,148 Total gain (loss) crude oil derivatives 25,715 101,813 (11,977 ) Total gain (loss) natural gas derivatives 72,538 36,279 (1,554 ) Crude oil derivative cash settlements paid (received) (91,953 ) 5,431 14,160 Natural gas derivative cash settlements received (40,972 ) (8,097 ) (7,104 ) Ending fair value of commodity derivatives $ 118,427 $ 153,099 $ 17,673 Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands): December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 ) December 31, 2014 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 223,778 $ (70,679 ) $ 153,099 Interest rate derivatives — — — Total derivative assets $ 223,778 $ (70,679 ) $ 153,099 Offsetting Derivative Liabilities: Commodity derivatives $ (70,679 ) $ 70,679 $ — Interest rate derivatives (2,080 ) — (2,080 ) Total derivative liabilities $ (72,759 ) $ 70,679 $ (2,080 ) As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 594,600 $68.37 $56.15 - $99.85 2017 182,500 $84.75 $84.75 As of December 31, 2015 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 2,928,000 $(1.60) $(1.50) - $(1.75) 2017 2,190,000 $(0.30) $(0.05) - $(0.75) As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2016 621,300 $63.37 $88.37 $106.40 2017 72,400 $60.00 $85.00 $104.20 As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below: Average Long Put Average Short Put Average Swap Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2016 183,000 $57.00 $82.00 $91.70 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of December 31, 2015 , Legacy had the following NYMEX Henry Hub and Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: Average Calendar Year Volumes (MMBtu) Price per MMBtu Price Range per MMBtu 2016 29,019,200 $3.40 $3.29 - $5.30 2017 27,600,000 $3.36 $3.29 - $3.39 2018 27,600,000 $3.36 $3.29 $3.39 2019 25,800,000 $3.36 $3.29 $3.39 As of December 31, 2015 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu 2016 5,580,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of December 31, 2015 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: 2016 Average Volumes (MMBtu) Price per MMBtu NWPL 14,977,818 $(0.19) San Juan 2,499,780 $(0.16) 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 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 and classified as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows: December 31, 2015 2014 2013 (In thousands) Beginning fair value of interest rate swaps $ (2,080 ) $ (4,759 ) $ (9,547 ) Total loss on interest rate swaps (1,548 ) (551 ) (1,165 ) Cash settlements paid 3,266 3,230 5,953 Ending fair value of interest rate swaps $ (362 ) $ (2,080 ) $ (4,759 ) The table below summarizes the interest rate swap assets and liabilities as of December 31, 2015 . Weighted Average Fixed Effective Maturity Estimated Fair Market Value at December 31, Notional Amount Rate Date Date 2015 (Dollars in thousands) $115,000 0.850 % 9/1/2015 9/1/2017 27 $235,000 1.363 % 9/1/2015 9/1/2019 (389 ) Total fair value of interest rate derivatives $ (362 )

Sales to Major Customers

Sales to Major Customers	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Sales to Major Customers	Business and Credit Concentrations Cash Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. Revenue and Accounts Receivable Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2015 , 2014 or 2013 . Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. Commodity Derivatives Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or three-way 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. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2015 , Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $118.4 million , collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. Sales to Major Customers For the year ended December 31, 2015 , Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the years ended December 31, 2014 and 2013 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2015 2014 2013 Enterprise (Teppco) Crude Oil, LP 6% 12% 17% Plains Marketing, LP 7% 10% 7% In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Legacy believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	Asset Retirement Obligation An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period in which it is incurred and becomes determinable. 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 additions to the ARO asset and liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon Legacy’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using Legacy’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. When obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from Legacy's balance sheet. Any difference in the cost to plug and the related liability is recorded as a gain or loss on Legacy's income statement in the disposal of assets line item. The following table reflects the changes in the ARO during the years ended December 31, 2015 , 2014 and 2013 . December 31, 2015 2014 2013 (In thousands) Asset retirement obligation — beginning of period $ 226,525 $ 175,786 $ 162,183 Liabilities incurred with properties acquired 60,526 50,487 10,969 Liabilities incurred with properties drilled 92 941 494 Liabilities settled during the period (2,615 ) (2,918 ) (2,441 ) Liabilities associated with properties sold (9,386 ) (5,891 ) (1,606 ) Current period accretion 11,263 8,120 6,187 Asset retirement obligation — end of period $ 286,405 $ 226,525 $ 175,786 Each year the Partnership reviews and, to the extent necessary, revises its asset retirement obligation estimates. During 2013 , 2014 and 2015 , no revisions of previous estimates were deemed necessary.

Partners' Equity

Partners' Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Partners' Equity	Partners' Equity On April 17, 2014, Legacy issued 2,000,000 of its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") in a public offering at a price of $25.00 per unit. On May 12, 2014 Legacy issued an additional 300,000 Series A Preferred Units pursuant to the underwriters’ option to purchase additional Series A Preferred Units. Legacy received aggregate net proceeds of approximately $55.2 million , after deducting underwriting discounts and offering expenses, from the offering of Series A Preferred Units during the year ended December 31, 2014. On June 17, 2014, Legacy issued 7,000,000 of its 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series B Preferred Units") in a public offering at a price of $25.00 per unit. On July 1, 2014, Legacy issued an additional 200,000 Series B Preferred Units pursuant to the underwriters' option to purchase additional Series B Preferred Units. Legacy received aggregate net proceeds of approximately $174.3 million , after deducting underwriting discounts and offering expenses, from the offering of Series B Preferred Units during the year ended December 31, 2014. Distributions on the Series A Preferred Units and Series B Preferred Units (collectively, the "Preferred Units") are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A Preferred Units and 5.26% for Series B Preferred Units, 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 the NASDAQ Global Select Market under the symbols "LGCYP" and "LGCYO,” respectively. On January 21, 2016, Legacy announced that its general partner suspended monthly cash distribution for both its Series A Preferred Units and its Series B Preferred Units. Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of the WPX Acquisition. The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy 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. The Unvested IDUs do not participate in cash distributions from Legacy until vested. The Unvested IDUs will automatically be forfeited on each of the first two anniversaries of the closing date of the WPX Acquisition in an amount per forfeiture equal to 66,666 Incentive Distribution Units and on the third anniversary of the closing date of the WPX Acquisition in an amount equal to 66,668 Incentive Distribution Units. The first such forfeiture of 66,666 units occurred on June 4, 2015. Unvested IDUs that have not been forfeited will vest ratably at a rate of 10,000 Incentive Distribution Units per $35.5 million of additional cash consideration that is paid by Legacy to WPX or to a third party (along with the fair market value of any non-cash consideration) in connection with the consummation of any transaction by which Legacy acquires oil and natural gas properties (or rights therein or other assets related thereto) from WPX or jointly with WPX. In addition, the vested and outstanding Incentive Distribution Units held by WPX may be converted by Legacy, subject to applicable conversion factors, into units on a one-for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus, 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 beginning three years after June 4, 2014. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX. Loss per unit The following table sets forth the computation of basic and diluted loss per unit: Years Ended December 31, 2015 2014 2013 (In thousands) Net loss $ (701,541 ) $ (283,645 ) $ (35,272 ) Distributions to preferred unitholders (19,000 ) (11,694 ) — Net loss attributable to unitholders (720,541 ) (295,339 ) (35,272 ) Weighted average number of units outstanding 68,928 60,053 57,220 Effect of dilutive securities: Restricted and phantom units — — — Weighted average units and potential units outstanding 68,928 60,053 57,220 Basic and diluted loss per unit $ (10.45 ) $ (4.92 ) $ (0.62 ) As of December 31, 2015 , 550,447 restricted units and 862,064 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. Additionally, as the conditions for conversion on the Incentive Distribution Units have not been met, they have been excluded from the calculation. As of December 31, 2014 , 254,183 restricted units and 323,965 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. As of December 31, 2013 , 234,686 restricted units and 189,143 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation Long Term Incentive Plan On March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights (“UARs”). The LTIP permits the grant of awards that may be made or settled in units up to an aggregate of 5,000,000 units. As of December 31, 2015 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 2,229,157 units have been made, comprised of 266,014 unit option awards, 904,551 restricted unit awards, 862,064 phantom unit awards and 196,528 unit awards. The UAR awards granted under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee of the board of directors ("Compensation Committee") of Legacy’s general partner. The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Due to Legacy’s historical practice of settling options, UARs and certain phantom unit awards in cash, Legacy accounts for unit options, UARS and certain phantom unit awards by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods. Unit Appreciation Rights A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method. During the year ended December 31, 2013 , Legacy issued (i) 156,650 UARs to employees which vest ratably over a three -year period and (ii) 77,506 UARs to employees which cliff-vest at the end of a three -year period. During the year ended December 31, 2014 , Legacy issued (i) 136,100 UARs to employees which vest ratably over a three -year period and (ii) 105,174 UARs to employees which cliff-vest at the end of a three -year period. During the year ended December 31, 2015 , Legacy issued (i) 204,500 UARs to employees which vest ratably over a three -year period and (ii) 96,520 UARs to employees which cliff-vest at the end of a three -year period. All of the UARs granted in 2015 , 2014 and 2013 expire seven years from the grant date and are exercisable when they vest. There were no unit options granted in 2015 , 2014 or 2013 . For the years ended December 31, 2015 , 2014 and 2013 , Legacy recorded compensation expense/(benefit) of $(10.7) thousand , $(1,260.0) thousand and $864.3 thousand , respectively, due to the changes in the compensation liability related to the above awards based on its use of the Black-Scholes model to estimate the December 31, 2015 , 2014 and 2013 fair value of these UARs (see Note 8). As of December 31, 2015 , there was a total of $374 of unrecognized compensation costs related to the unexercised and non-vested portion of the UARs. At December 31, 2015 , this cost was expected to be recognized over a weighted-average period of 2.66 years. Compensation expense is based upon the fair value as of the balance sheet date and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 59% and employed the Black-Scholes model to estimate the December 31, 2015 fair value to be realized as compensation cost based on the percentage of the service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 5.3% . The Partnership will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $0.60 per unit. A summary of UAR activity for the year ended December 31, 2015 , 2014 and 2013 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2013 516,219 $ 24.71 Granted 234,156 $ 26.53 Exercised (96,166 ) $ 20.21 Forfeited (27,166 ) $ 26.74 Outstanding at December 31, 2013 627,043 $ 25.99 5.16 $ 1,518,416 UARs exercisable at December 31, 2013 240,288 $ 24.02 3.80 $ 1,061,542 Outstanding at January 1, 2014 627,043 $ 25.99 Granted 243,274 $ 28.21 Exercised (137,252 ) $ 24.35 Forfeited (61,836 ) $ 27.27 Outstanding at December 31, 2014 671,229 $ 26.97 5.15 $ — UARs exercisable at December 31, 2014 220,056 $ 25.50 3.51 $ — Outstanding at January 1, 2015 671,229 $ 26.97 Granted 301,020 $ 6.49 Forfeited (36,133 ) $ 21.07 Outstanding at December 31, 2015 936,116 $ 20.61 4.91 $ — UARs exercisable at December 31, 2015 372,049 $ 26.45 3.28 $ — The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2015 : Non-Vested UARs Number of Units Weighted- Average Exercise Price Non-vested at January 1, 2015 451,173 $ 27.69 Granted 301,020 6.49 Vested (151,993 ) 27.84 Forfeited (36,133 ) 21.07 Non-vested at December 31, 2015 564,067 $ 16.76 Legacy has used a weighted-average risk free interest rate of 1.7% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at December 31, 2015 . Expected life represents the period of time that options and UARs are expected to be outstanding and is based on the Partnership’s best estimate. The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model: Year Ended December 31, 2015 2014 2013 Expected life (years) 4.91 5.15 5.16 Annual interest rate 1.7 % 1.6 % 1.4 % Annual distribution rate per unit $0.60 $2.44 $2.34 Volatility 59 % 38 % 50 % Phantom Units Legacy has also issued phantom units under the LTIP to both executive officers, as described below, and certain other employees. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive, in the case of non-executive employees, cash valued at the closing price of units on the vesting date, or, at the discretion of the Compensation Committee, the same number of Partnership units. Because Legacy’s current intent is to settle non-executive phantom unit awards in cash, Legacy is accounting for these phantom units by utilizing the liability method. In the case of executive employees, during 2013 the Compensation Committee revised prior grants of phantom units made to executive officers to eliminate any election for cash payment. As these awards can now only be settled in Partnership units, Legacy is accounting for these phantom units by utilizing the equity method as described in ASC 718. During March 2013 , the Compensation Committee approved the award of 46,430 subjective, or service-based, phantom units and 76,723 objective, or performance-based, phantom units to Legacy’s five executive officers. During March 2014 , the Compensation Committee approved the award of 117,197 subjective, or service-based, phantom units and 102,572 objective, or performance-based, phantom units to Legacy’s executive officers. During February 2015 , the Compensation Committee approved the award of 341,251 subjective, or service-based, phantom units and 259,998 objective, or performance-based, phantom units to Legacy's executive officers. Compensation expense related to the phantom units and associated DERs was $3.4 million , $2.3 million and $1.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Restricted Units During the year ended December 31, 2013 , Legacy issued an aggregate of 85,728 restricted units to both non-executive employees and certain executives. The majority of these restricted units awarded vest ratably over a three -year period, beginning on the date of grant. During the year ended December 31, 2014 , Legacy issued an aggregate of 127,845 restricted units to non-executive employees. The majority of these restricted units awarded vest ratably over a three -year period. During the year ended December 31, 2015 , Legacy issued an aggregate of 381,860 restricted units to both non-executive employees and an executive employee. The restricted units awarded to non-executive employees vest ratably over a three -year period beginning at the date of grant. The restricted units granted to the executive employee vest ratably over a three -year period for a portion of the restricted units, with the remainder vesting in full at the end of a five -year period. Compensation expense related to restricted units was $2.7 million , $2.3 million and $2.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , there was a total of $5.1 million of unrecognized compensation costs related to the non-vested portion of these restricted units. At December 31, 2015 , this cost was expected to be recognized over a weighted-average period of 2.3 years. Pursuant to the provisions of ASC 718, Legacy’s issued units as reflected in the accompanying consolidated balance sheet at December 31, 2015 , do not include 550,447 units related to unvested restricted unit awards. Board Units On May 14, 2013 , Legacy granted and issued 3,715 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $27.39 at the time of issuance. On May 15, 2014 , Legacy granted and issued 3,628 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $27.50 at the time of issuance. On June 15, 2015 , Legacy granted and issued 11,025 units to each of its six non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $9.13 at the time of issuance. None of these units were subject to vesting. Legacy recognized the expense associated with the unit grants on the date of grant.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors On April 2, 2014, we filed a registration statement on Form S-3 with the Securities and Exchange Commission ("SEC") to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by Legacy Reserves Finance Corporation. The registration statement also registered guarantees of debt securities by Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by our 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of our wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in Note 3 - Long-Term Debt . The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 21, 2016, the board of directors of Legacy’s general partner announced the suspension of cash distributions to Legacy's unitholders. On January 21, 2016, Legacy announced that its general partner suspended monthly cash distribution for both its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and its 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units. Effective February 19, 2016, Legacy entered into the Seventh Amendment to the Current Credit Agreement (the “Seventh Amendment”). The Seventh Amendment amends certain provisions set forth in the Current Credit Agreement to: • establish the applicable margin on (i) Eurodollar loans of not less than 2.00% and not more than 3.00% (to be determined by the percentage of the borrowing base utilized by Legacy) and (ii) alternate base rate loans of not less than 1.00% and not more than 2.00% (to be determined by the percentage of the borrowing base utilized by Legacy); provided, that if the ratio of our first lien debt as of the last day of any fiscal quarter to its EBITDA for the four fiscal quarters ending on such day is greater than 3.00 to 1.00, then the applicable margin shall be increased by 0.50% during the next succeeding fiscal quarter; • in the event that Legacy is required to redeem any secured second lien notes (described below), Legacy shall first prepay the loans and cash collateralize any letter of credit exposure in an amount equal to the applicable redemption amount; • in the event that at the close of any business day the aggregate amount of cash and cash equivalents, marketable securities and other liquid financial assets of Legacy exceeds $20 million (excluding funds received by Legacy after 10:00 a.m. on such day), then Legacy shall prepay the loans and cash collateralize any letter of credit exposure with such excess; • require that the oil and gas properties of Legacy mortgaged in favor of the Lenders as collateral security for the loans represent not less than 90% of the total value of the oil and gas properties of Legacy evaluated in the most recently completed reserve report; • permit the payment by Legacy of cash dividends to its equity holders out of available cash in accordance with our partnership agreement so long as before and immediately after such payment (i) no default or event of default occurred or would result therefrom, (ii) Legacy has unused commitments of not less than 15% of the total commitments then in effect under the Current Credit Agreement, (iii) the ratio of Legacy’s total debt at the time of such payment to its 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 equal to or less than 4.00 to 1.00; • permit the redemption or repurchase of preferred equity securities, preferred limited partnership interests or preferred units of Legacy: (i) using cash proceeds from the sale of equity securities or in exchange for equity securities of Legacy, or (ii) so long as before and immediately after such repurchase or redemption, (1) no default or event of default occurred or would result therefrom, (2) Legacy has unused commitments of less than 15% of the total commitments then in effect under the Credit Agreement, and (3) the ratio of Legacy’s total debt at the time of the redemption or repurchase to its 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 equal to or less than 4.00 to 1.00; • permit the redemption or repurchase of Legacy’s senior unsecured notes (a) using cash proceeds from the sale of equity securities or in exchange for equity securities of Legacy, or with the proceeds of permitted refinancing debt, (b) so long as (1) before and immediately after such redemption (A) Legacy has unused commitments of not less than the greater of (i) 20% of the total commitments then in effect under the Current Credit Agreement, and (ii) $100,000,000 , (B) Legacy is in pro forma compliance with the first lien debt to EBITDA covenant such that its ratio of first lien debt to EBITDA would not exceed 3.00 to 1.00 (or 2.50 to 1.00 on any date of determination occurring on or after July 1, 2017), (C) no default or event of default occurred or would result therefrom and (2) each such redemption is made solely with the proceeds from the permitted sales of property, provided, that (w) such redemption shall be made within 90 days of the related sale of property, (x) the amount of sale proceeds used for such redemption shall not exceed 50% of the sale proceeds of such property, (y) the redemption prices shall not exceed 50% of the stated principal amount of senior unsecured notes redeemed, and (z) the aggregate amount of all sale proceeds used for all such redemptions shall not exceed $75 million , and (c) in exchange for secured second lien notes pursuant to a senior debt exchange or in exchange for equity interests of Legacy; • permit the issuance by the Company of secured second lien notes solely in exchange for our outstanding senior unsecured notes pursuant to one or more senior debt exchanges; provided that: (i) such debt shall be (A) in an aggregate principal amount not to exceed $400 million and (B) such debt is subject to an Intercreditor Agreement at all times; and (ii) such debt shall not (A) have any scheduled principal amortization or have a scheduled maturity date or a date of mandatory redemption in full prior to 120 days after April 1, 2019, or (B) contain terms and conditions, taken as a whole, more restrictive than those set forth in the Current Credit Agreement and (C) be guaranteed by any subsidiary or other person unless such subsidiary or other person has guaranteed Legacy’ indebtedness under the Current Credit Agreement pursuant to the Guaranty Agreement; • restrict the redemption of any secured second lien notes; provided, that if no default, event of default or borrowing base deficiency has occurred or would result therefrom Legacy may redeem secured second lien notes with the proceeds of the sale of equity securities or permitted refinancing debt, or in exchange for its equity interests; • reduce the borrowing base from $900 million to $725 million ; • not permit, as of the last day of any fiscal quarter, Legacy’s ratio of EBITDA for the four fiscal quarters then ending to interest expense for such period to be less than (i) 2.50 to 1.00 for the fiscal quarters ending December 31, 2015 and March 31, 2016, (ii) 2.00 to 1.00 for the fiscal quarters ending June 30, 2016, through the fiscal quarter ending June 30, 2017, and (iii) 2.50 to 1.00 for the fiscal quarter ending September 30, 2017 and each fiscal quarter thereafter; and • eliminate Legacy’s ratio of secured debt to EBITDA covenant and not permit, at any time, the ratio of Legacy’s first lien debt as of such time to EBITDA for the four fiscal quarters ending on last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to be greater than: (i) 3.50 to 1.00, at any time during the period from and including the effective date of the Seventh Amendment through December 31, 2016, (ii) 3.25 to 1.00, at any time during the fiscal quarter ending March 31, 2017, (iii) 3.00 to 1.00, at any time during the fiscal quarter ending June 30, 2017 and (iv) 2.50 to 1.00, at any time on or after July 1, 2017. All capitalized terms not defined herein have the meaning assigned to them in the Current Credit Agreement, as amended by the Seventh Amendment. From January 1, 2016 to February 22, 2016, Legacy repurchased a face amount of $104.5 million of Senior Notes at market prices.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.
Accounts Receivable	Accounts Receivable Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10).
Oil and Natural Gas Properties and Oil, NGLs and Natural Gas Reserve Quantities	Oil and Natural Gas Properties Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties 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 Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2015 , Legacy recognized $633.8 million of impairment expense, $598.1 million of of which was in 218 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2015 , which decreased the expected future cash flows below the carrying value of the assets. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2014 , Legacy recognized $448.7 million of impairment expense, $413.3 million of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014 , which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2013 , Legacy recognized $78.0 million of impairment expense on 98 separate producing fields, due primarily to the decrease in commodity prices primarily related to natural gas differentials during the year ended December 31, 2013 , combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. During the years ended December 31, 2015 , 2014 and 2013 , Legacy recognized $35.7 million , $35.0 million and $7.8 million of impairment of unproven properties, respectively. (d) Oil, NGLs and Natural Gas Reserve Quantities Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered.
Income Taxes	Income Taxes Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. Legacy recorded income tax (expense) benefit of $1.5 million , $0.9 million and $(0.6) million for the years ended December 31, 2015 , 2014 and 2013 , respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.4 billion at December 31, 2015 .
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9).
Use of Estimates	Use of Estimates Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues.
Revenue Recognition	Revenue Recognition Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments 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. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. 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 recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. Legacy uses the “net-back” method of accounting for transportation arrangements of its natural gas sales. Legacy sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its purchasers and reflected in the wellhead price. Legacy’s contracts with respect to the sale of its natural gas produced, with one immaterial exception, provide Legacy with a net price payment. That is, when Legacy is paid for its natural gas by its purchasers, Legacy receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of Legacy’s contracts, the payment statements Legacy receives from its purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, Legacy’s revenues are recorded at this single net price. 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, 2015 , 2014 and 2013 . Legacy is paid a monthly operating fee for each well it operates for outside owners proportionate to each owner's working interest. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense.
Investments	Investments Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.
Intangible assets	Intangible assets Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life.
Environmental	Environmental Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
Income (Loss) Per Unit	Income (Loss) Per Unit Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12).
Redemption of Units	Redemption of Units Units redeemed are recorded at cost.
Segment Reporting	Segment Reporting Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes.
Unit-Based Compensation	Unit-Based Compensation Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2015 , do not include 550,447 units related to unvested restricted unit awards.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of components of accrued oil and natural gas liabilities	Below are the components of accrued oil and natural gas liabilities as of December 31, 2015 and 2014 . December 31, 2015 2014 (In thousands) Revenue payable to joint interest owners $ 15,253 $ 19,267 Accrued lease operating expense 19,007 21,177 Accrued capital expenditures 2,881 20,773 Accrued ad valorem tax 8,723 9,382 Other 4,709 8,016 $ 50,573 $ 78,615

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Schedule of long-term debt	Long-term debt consists of the following at December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Credit Facility due 2019 $ 608,000 109,000 8% Senior Notes due 2020 300,000 300,000 6.625% Senior Notes due 2021 550,000 550,000 1,458,000 959,000 Unamortized discount on Senior Notes (17,604 ) (20,124 ) Total long term debt $ 1,440,396 $ 938,876
8% Senior Notes due 2020
Debt Instrument [Line Items]
Schedule of debt redemption	Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. Year Percentage 2016 104.000 % 2017 102.000 % 2018 100.000 %
6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Schedule of debt redemption	Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. Year Percentage 2017 103.313 % 2018 101.656 % 2019 and thereafter 100.000 %

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Schedule of unaudited pro forma results of operations	The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013 and the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future: Year Ended December 31, 2015 2014 2013 (In thousands) Revenues $ 380,619 $ 687,829 $ 549,968 Net loss $ (713,364 ) $ (243,197 ) $ (50,041 ) Loss per unit — basic and diluted $ (10.35 ) $ (4.05 ) $ (0.87 ) Units used in computing loss per unit: Basic 68,928 60,053 57,220 Diluted 68,928 60,053 57,220 The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the WPX Acquisition and the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. Year Ended December 31, 2015 2014 2013 WPX Acquisition (In thousands) Revenues $ 69,504 $ 48,470 $ — Excess of revenues over direct operating expenses $ 22,324 $ 22,333 $ — Anadarko Acquisitions Revenues $ 22,881 $ — $ — Excess of revenues over direct operating expenses $ 12,373 $ — $ —
WPX acquisition
Business Acquisition [Line Items]
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed	The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 422,739 Future abandonment costs (62,748 ) Fair value of net assets acquired $ 359,991
Anadarko Acquisitions
Business Acquisition [Line Items]
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed	The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 459,540 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 432,189

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis	The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 : Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Total Carrying Description (Level 1) (Level 2) (Level 3) Value as of (In thousands) LTIP liability(a) $ — $ — $ — $ — Oil and natural gas derivatives — 122,920 (4,493 ) 118,427 Interest rate swaps — (362 ) — (362 ) Total as of December 31, 2015 $ — $ 122,558 $ (4,493 ) $ 118,065 LTIP liability(a) $ — $ (11 ) $ — $ (11 ) Oil and natural gas derivatives — 152,544 555 153,099 Interest rate swaps — (2,080 ) — (2,080 ) Total as of December 31, 2014 $ — $ 150,453 $ 555 $ 151,008 ____________________ (a) See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet.
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) December 31, 2015 2014 2013 (In thousands) Beginning balance $ 555 $ 20,615 $ 29,966 Total gains (losses) (10,029 ) (6,185 ) 4,671 Settlements 4,981 677 (6,722 ) Transfers — (14,552 ) (a) (7,300 ) (b) Ending balance $ (4,493 ) $ 555 $ 20,615 Gains included in earnings relating to derivatives still held as of December 31, 2015, 2014 and 2013 $ (4,493 ) $ 555 $ 1,407 (a) During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps have been transferred to Level 2 instruments. (b) During December 2013, Legacy amended three separate contracts with two counterparties to convert contracts from three-way collar contracts to fixed price swap contracts. As fixed price swap contracts are classified as Level 2, the value on the date of the amendment was transferred from a Level 3 classification to Level 2.
Schedule of fair value measurements of proved oil and natural gas properties	Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2015 and 2014 consist of: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description (Level 1) (Level 2) (Level 3) (In thousands) 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 2014 Impairment(a) $ — $ — $ 254,266 Acquisitions(b) $ — $ — $ 536,334 ____________________ (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 year ended December 31, 2015 , Legacy incurred impairment charges of $598.1 million as oil and natural gas properties with a net cost basis of $983.6 million were written down to their fair value of $385.5 million . During the year ended December 31, 2014 , Legacy incurred impairment charges of $413.3 million as oil and natural gas properties with a net cost basis of $667.5 million were written down to their fair value of $254.3 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 remaining $35.7 million of impairment during the year ended December 31, 2015 represented impairment of unproved properties acquired since 2010 that are no longer viable. The remaining $35.4 million of impairment during the year ended December 31, 2014 was $34.95 million of impairment of unproved properties acquired since 2010 that were no longer viable and $0.5 million of impairment of goodwill related to an acquisition completed in 2010. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2015 , Legacy acquired oil and natural gas properties with a fair value of $540.3 million in the Anadarko Acquisitions and 3 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2014 , Legacy acquired oil and natural gas properties with a fair value of $536.3 million in the WPX Acquisition and 6 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Derivative Financial Instrume28

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of reconciliation of the changes in fair value of Legacy's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2015 , 2014 , and 2013 . December 31, 2015 2014 2013 (In thousands) Beginning fair value of commodity derivatives $ 153,099 $ 17,673 $ 24,148 Total gain (loss) crude oil derivatives 25,715 101,813 (11,977 ) Total gain (loss) natural gas derivatives 72,538 36,279 (1,554 ) Crude oil derivative cash settlements paid (received) (91,953 ) 5,431 14,160 Natural gas derivative cash settlements received (40,972 ) (8,097 ) (7,104 ) Ending fair value of commodity derivatives $ 118,427 $ 153,099 $ 17,673
Schedule of gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities	Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands): December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 ) December 31, 2014 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 223,778 $ (70,679 ) $ 153,099 Interest rate derivatives — — — Total derivative assets $ 223,778 $ (70,679 ) $ 153,099 Offsetting Derivative Liabilities: Commodity derivatives $ (70,679 ) $ 70,679 $ — Interest rate derivatives (2,080 ) — (2,080 ) Total derivative liabilities $ (72,759 ) $ 70,679 $ (2,080 )
Schedule of notional amounts of outstanding derivative positions	As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 594,600 $68.37 $56.15 - $99.85 2017 182,500 $84.75 $84.75 As of December 31, 2015 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 2,928,000 $(1.60) $(1.50) - $(1.75) 2017 2,190,000 $(0.30) $(0.05) - $(0.75) As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2016 621,300 $63.37 $88.37 $106.40 2017 72,400 $60.00 $85.00 $104.20 As of December 31, 2015 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below: Average Long Put Average Short Put Average Swap Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2016 183,000 $57.00 $82.00 $91.70 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of December 31, 2015 , Legacy had the following NYMEX Henry Hub and Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: Average Calendar Year Volumes (MMBtu) Price per MMBtu Price Range per MMBtu 2016 29,019,200 $3.40 $3.29 - $5.30 2017 27,600,000 $3.36 $3.29 - $3.39 2018 27,600,000 $3.36 $3.29 $3.39 2019 25,800,000 $3.36 $3.29 $3.39 As of December 31, 2015 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu 2016 5,580,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of December 31, 2015 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: 2016 Average Volumes (MMBtu) Price per MMBtu NWPL 14,977,818 $(0.19) San Juan 2,499,780 $(0.16)
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: December 31, 2015 2014 2013 (In thousands) Beginning fair value of interest rate swaps $ (2,080 ) $ (4,759 ) $ (9,547 ) Total loss on interest rate swaps (1,548 ) (551 ) (1,165 ) Cash settlements paid 3,266 3,230 5,953 Ending fair value of interest rate swaps $ (362 ) $ (2,080 ) $ (4,759 )
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap assets and liabilities as of December 31, 2015 . Weighted Average Fixed Effective Maturity Estimated Fair Market Value at December 31, Notional Amount Rate Date Date 2015 (Dollars in thousands) $115,000 0.850 % 9/1/2015 9/1/2017 27 $235,000 1.363 % 9/1/2015 9/1/2019 (389 ) Total fair value of interest rate derivatives $ (362 )

Sales to Major Customers (Table

Sales to Major Customers (Tables)	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Schedule of revenue by major customer	For the years ended December 31, 2014 and 2013 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2015 2014 2013 Enterprise (Teppco) Crude Oil, LP 6% 12% 17% Plains Marketing, LP 7% 10% 7%

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Schedule of changes in asset retirement obligations	The following table reflects the changes in the ARO during the years ended December 31, 2015 , 2014 and 2013 . December 31, 2015 2014 2013 (In thousands) Asset retirement obligation — beginning of period $ 226,525 $ 175,786 $ 162,183 Liabilities incurred with properties acquired 60,526 50,487 10,969 Liabilities incurred with properties drilled 92 941 494 Liabilities settled during the period (2,615 ) (2,918 ) (2,441 ) Liabilities associated with properties sold (9,386 ) (5,891 ) (1,606 ) Current period accretion 11,263 8,120 6,187 Asset retirement obligation — end of period $ 286,405 $ 226,525 $ 175,786

Partners' Equity (Tables)

Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of computation of basic and diluted income (loss) per unit	The following table sets forth the computation of basic and diluted loss per unit: Years Ended December 31, 2015 2014 2013 (In thousands) Net loss $ (701,541 ) $ (283,645 ) $ (35,272 ) Distributions to preferred unitholders (19,000 ) (11,694 ) — Net loss attributable to unitholders (720,541 ) (295,339 ) (35,272 ) Weighted average number of units outstanding 68,928 60,053 57,220 Effect of dilutive securities: Restricted and phantom units — — — Weighted average units and potential units outstanding 68,928 60,053 57,220 Basic and diluted loss per unit $ (10.45 ) $ (4.92 ) $ (0.62 )

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of option and UAR activity	A summary of UAR activity for the year ended December 31, 2015 , 2014 and 2013 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2013 516,219 $ 24.71 Granted 234,156 $ 26.53 Exercised (96,166 ) $ 20.21 Forfeited (27,166 ) $ 26.74 Outstanding at December 31, 2013 627,043 $ 25.99 5.16 $ 1,518,416 UARs exercisable at December 31, 2013 240,288 $ 24.02 3.80 $ 1,061,542 Outstanding at January 1, 2014 627,043 $ 25.99 Granted 243,274 $ 28.21 Exercised (137,252 ) $ 24.35 Forfeited (61,836 ) $ 27.27 Outstanding at December 31, 2014 671,229 $ 26.97 5.15 $ — UARs exercisable at December 31, 2014 220,056 $ 25.50 3.51 $ — Outstanding at January 1, 2015 671,229 $ 26.97 Granted 301,020 $ 6.49 Forfeited (36,133 ) $ 21.07 Outstanding at December 31, 2015 936,116 $ 20.61 4.91 $ — UARs exercisable at December 31, 2015 372,049 $ 26.45 3.28 $ —
Schedule of status of the Partnership’s non-vested UARs	The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2015 : Non-Vested UARs Number of Units Weighted- Average Exercise Price Non-vested at January 1, 2015 451,173 $ 27.69 Granted 301,020 6.49 Vested (151,993 ) 27.84 Forfeited (36,133 ) 21.07 Non-vested at December 31, 2015 564,067 $ 16.76
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: Year Ended December 31, 2015 2014 2013 Expected life (years) 4.91 5.15 5.16 Annual interest rate 1.7 % 1.6 % 1.4 % Annual distribution rate per unit $0.60 $2.44 $2.34 Volatility 59 % 38 % 50 %

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Other Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)field	Dec. 31, 2014USD ($)field	Dec. 31, 2013USD ($)field
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General partner's equity, percent	0.03%	0.03%
Term of right to receive distributions of available cash after quarter end	45 days
Minimum percentage of unitholder approval to remove general partner	66.67%
Term of right to receive information reasonably required for tax reporting purposes after close of year	90 days
Property, Plant and Equipment [Line Items]
Impairment expense	$ 633,805	$ 448,714	$ 85,757
Impairment expense recorded of proved and unproved oil and natural gas properties		$ 413,300	$ 78,000
Number of impaired fields | field	218	250	98
Proved Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Impairment expense recorded of proved and unproved oil and natural gas properties	$ 598,100
Unproved Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Impairment expense recorded of proved and unproved oil and natural gas properties	$ 35,700	$ 34,950	$ 7,800

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Contingency [Line Items]
Income tax expense (benefit)	$ (1,498)	$ (859)	$ 649
Partnership’s book basis in its net assets excess of Partnership’s net tax basis	$ 1,400,000
Texas | State jurisdiction
Income Tax Contingency [Line Items]
Franchise tax rate	1.00%

Summary of Significant Accoun35

Summary of Significant Accounting Policies - Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Estimated economic useful life	15 years
Expected amortization expense, 2016	$ 417
Expected amortization expense, 2017	396
Expected amortization expense, 2018	358
Expected amortization expense, 2019	349
Expected amortization expense, 2020	$ 322

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Unit-Based Compensation (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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)	550,447	254,183	234,686

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue payable to joint interest owners	$ 15,253	$ 19,267
Accrued lease operating expense	19,007	21,177
Accrued capital expenditures	2,881	20,773
Accrued ad valorem tax	8,723	9,382
Other	4,709	8,016
Accrued oil and natural gas liabilities	$ 50,573	$ 78,615

Fair Values of Financial Inst38

Fair Values of Financial Instruments (Details) - Senior notes - USD ($) $ in Millions	Dec. 31, 2015	Dec. 04, 2012
8% Senior Notes due 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Stated interest rate	8.00%	8.00%
8% Senior Notes due 2020 | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of notes payable	$ 84
6.625% Senior Notes due 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Stated interest rate	6.625%
6.625% Senior Notes due 2021 | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of notes payable	$ 165.6

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	May. 13, 2014	May. 28, 2013	Dec. 04, 2012
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,458,000,000	$ 959,000,000
Unamortized discount on Senior Notes	(17,604,000)	(20,124,000)
Total long term debt	1,440,396,000	938,876,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, gross	$ 300,000,000	300,000,000			$ 300,000,000
Stated interest rate	8.00%				8.00%
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 550,000,000	550,000,000	$ 300,000,000	$ 250,000,000
Stated interest rate	6.625%
Credit Facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 608,000,000	$ 109,000,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility (Details)	Apr. 01, 2014USD ($)	Mar. 10, 2011USD ($)	Dec. 31, 2015USD ($)	Feb. 23, 2016USD ($)	Feb. 19, 2016USD ($)	Dec. 31, 2014USD ($)	May. 13, 2014USD ($)	May. 28, 2013USD ($)	Dec. 04, 2012USD ($)
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 1,458,000,000			$ 959,000,000
Previous Credit Agreement
Line of Credit Facility [Line Items]
Expiration period		5 years
Maximum borrowing capacity		$ 1,000,000,000
Credit Facility due 2019
Line of Credit Facility [Line Items]
Expiration period	5 years
Maximum borrowing capacity	$ 1,500,000,000
Minimum percent of total property value securing credit agreement	90.00%
Current borrowing capacity			$ 900,000,000
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 EBITDA			2.5
Ratio of EBITDA to interest expense, minimum			2.5
Ratio of current assets to current liabilities, minimum			1
Long-term debt, gross			$ 608,000,000			109,000,000
Interest rate at period end			2.40%
Remaining borrowing capacity			$ 291,600,000
Interest Paid			9,400,000
Credit Facility due 2019 | one-, two-, three- or six-month LIBOR | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
Credit Facility due 2019 | one-, two-, three- or six-month LIBOR | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.50%
Credit Facility due 2019 | ABR, Federal Funds
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Credit Facility due 2019 | Standard ABR | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Credit Facility due 2019 | Standard ABR | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
Credit Facility due 2019 | ABR, one-month LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Letters of credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000
Subsequent Event | Credit Facility due 2019
Line of Credit Facility [Line Items]
Current borrowing capacity					$ 725,000,000
Remaining borrowing capacity				$ 105,600,000
8% Senior Notes due 2020 | Senior notes
Line of Credit Facility [Line Items]
Long-term debt, gross			300,000,000			300,000,000			$ 300,000,000
Interest Paid			24,000,000
6.625% Senior Notes due 2021 | Senior notes
Line of Credit Facility [Line Items]
Long-term debt, gross			550,000,000			$ 550,000,000	$ 300,000,000	$ 250,000,000
Interest Paid			$ 36,400,000

Long-Term Debt - Senior Notes (

Long-Term Debt - Senior Notes (Details) - USD ($)	May. 13, 2014	May. 28, 2013	Dec. 04, 2012	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, gross				$ 1,458,000,000	$ 959,000,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, gross			$ 300,000,000	$ 300,000,000	300,000,000
Stated interest rate			8.00%	8.00%
Issuance percent of par			97.848%
Percent of notes eligible of early redemption				35.00%
Senior notes | 8% Senior Notes due 2020 | Company Option
Debt Instrument [Line Items]
Redemption price percentage				108.00%
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 | Redemption Premium Year Four
Debt Instrument [Line Items]
Redemption price percentage				104.00%
Senior notes | 8% Senior Notes due 2020 | Redemption Premium Year Five
Debt Instrument [Line Items]
Redemption price percentage				102.00%
Senior notes | 8% Senior Notes due 2020 | Redemption Premium Year Six
Debt Instrument [Line Items]
Redemption price percentage				100.00%
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 300,000,000	$ 250,000,000		$ 550,000,000	$ 550,000,000
Stated interest rate				6.625%
Issuance percent of par	99.00%	98.405%
Percent of notes eligible of early redemption				35.00%
Senior notes | 6.625% Senior Notes due 2021 | Company Option
Debt Instrument [Line Items]
Redemption price percentage				106.625%
Senior notes | 6.625% Senior Notes due 2021 | Change in Control
Debt Instrument [Line Items]
Redemption price percentage				101.00%
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Four
Debt Instrument [Line Items]
Redemption price percentage				103.313%
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Five
Debt Instrument [Line Items]
Redemption price percentage				101.656%
Senior notes | 6.625% Senior Notes due 2021 | Redemption Premium Year Six
Debt Instrument [Line Items]
Redemption price percentage				100.00%
Legacy Reserves Finance Corporation
Debt Instrument [Line Items]
Ownership interest	100.00%	100.00%	100.00%

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 31, 2015	Jun. 04, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pro Forma Operating Results
Revenues			$ 380,619	$ 687,829	$ 549,968
Net loss			$ (713,364)	$ (243,197)	$ (50,041)
Income (loss) per unit - basic and diluted (in dollars per share)			$ (10.35)	$ (4.05)	$ (0.87)
Units Used In Computing Income (Loss) Per Unit [Abstract]
Basic (in shares)			68,928,000	60,053,000	57,220,000
Diluted (in shares)			68,928,000	60,053,000	57,220,000
WPX acquisition
Business Acquisition [Line Items]
Purchase price		$ 360,000
Consideration transferred (in shares)		300,000
Estimated issuance date fair value of consideration transfered		$ 30,800
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed
Proved oil and natural gas properties including related equipment		422,739
Future abandonment costs		(62,748)
Fair value of net assets acquired		$ 359,991
Units Used In Computing Income (Loss) Per Unit [Abstract]
Revenues			$ 69,504	$ 48,470	$ 0
Excess of revenues over direct operating expenses			22,324	22,333	0
WPX acquisition | General and administrative expense
Business Acquisition [Line Items]
Acquisition costs				5,400
Anadarko Acquisitions
Business Acquisition [Line Items]
Acquisition costs			2,400
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed
Proved oil and natural gas properties including related equipment	$ 459,540
Future abandonment costs	(27,351)
Fair value of net assets acquired	432,189
Units Used In Computing Income (Loss) Per Unit [Abstract]
Revenues			22,881	0	0
Excess of revenues over direct operating expenses			$ 12,373	$ 0	$ 0
WGR Acquisition
Business Acquisition [Line Items]
Purchase price	$ 96,700
Percentage of voting interest acquired	100.00%
Anadarko E&P Acquisition
Business Acquisition [Line Items]
Purchase price	$ 335,500
Immediate vesting | WPX acquisition
Business Acquisition [Line Items]
Consideration transferred (in shares)		100,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015
President/CEO and Director, EVP, CDO
Related Party Transaction [Line Items]
Noncontrolling ownership interest in third party by related party		4.16%
Monthly rent expense		$ 102,465
Water Transfer Services | Blue Quail Energy Services, LLC | Board of Directors Chairman and Director
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 382,629
Reimbursement | Moriah Powder River LLC | Board of Directors Chairman and Director
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 500,000

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl
Loss Contingencies [Line Items]
Purchase obligation, calculated floor price | $ / bbl	57.14
Estimated total future purchase obligation | $	$ 49.8
Officer
Loss Contingencies [Line Items]
Employment agreements with officers, severance pay consideration period, minimum	24 months
Employment agreements with officers, severance pay consideration period, maximum	36 months

Business and Credit Concentra45

Business and Credit Concentrations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Risks and Uncertainties [Abstract]
Bad debt expense	$ 0	$ 0	$ 0
Fair value of derivative transactions	$ 118,400,000

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2013USD ($)counterpartycontract	Dec. 31, 2015USD ($)transaction	Dec. 31, 2014USD ($)transaction	Dec. 31, 2013USD ($)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment expense recorded of proved and unproved oil and natural gas properties			$ 413,300	$ 78,000
Total oil and natural gas assets		$ 1,408,956	1,639,974
Goodwill impairment recognized			500
Proved Oil and Gas Properties
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment expense recorded of proved and unproved oil and natural gas properties		598,100
Unproved Oil and Gas Properties
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment expense recorded of proved and unproved oil and natural gas properties		35,700	34,950	7,800
Recurring
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability		0	(11)
Fair value of assets (liabilities)		118,065	151,008
Recurring | Oil and natural gas derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets		118,427	153,099
Recurring | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability		(362)	(2,080)
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability		0	0
Fair value of assets (liabilities)		0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Oil and natural gas derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets		0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability		0	0
Recurring | Significant Other Observable Inputs (Level 2)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability		0	(11)
Fair value of assets (liabilities)		122,558	150,453
Recurring | Significant Other Observable Inputs (Level 2) | Swap
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Number of contracts amended | contract	3
Number of counterparties | counterparty	2
Recurring | Significant Other Observable Inputs (Level 2) | Oil and natural gas derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets		122,920	152,544
Recurring | Significant Other Observable Inputs (Level 2) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability		(362)	(2,080)
Recurring | Significant Unobservable Inputs (Level 3)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability		0	0
Fair value of assets (liabilities)		(4,493)	555
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance		555	20,615	29,966
Total gains (losses)		(10,029)	(6,185)	4,671
Settlements		4,981	677	(6,722)
Transfers		0	(14,552)	(7,300)
Ending balance	$ 20,615	(4,493)	555	20,615
Gains (losses) included in earnings relating to derivatives still held as of December 31, 2013, 2012 and 2011		(10,029)	(6,185)	4,671
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Total gains (losses)		(4,493)	555	1,407
Gains (losses) included in earnings relating to derivatives still held as of December 31, 2013, 2012 and 2011		(4,493)	555	$ 1,407
Recurring | Significant Unobservable Inputs (Level 3) | Oil and natural gas derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative assets		(4,493)	555
Recurring | Significant Unobservable Inputs (Level 3) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability		0	0
Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Total oil and natural gas assets		0	0
Acquisitions		0	0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Total oil and natural gas assets		0	0
Acquisitions		0	0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment expense recorded of proved and unproved oil and natural gas properties			35,400
Oil and gas properties, gross		983,600	667,500
Total oil and natural gas assets		385,506	254,266
Acquisitions		$ 540,347	$ 536,334
Number of immaterial transactions | transaction		3	6
Nonrecurring | Significant Unobservable Inputs (Level 3) | Unproved Oil and Gas Properties
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment expense recorded of proved and unproved oil and natural gas properties		$ 35,700

Derivative Financial Instrume47

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	$ 99,971	$ 140,771	$ (8,743)
Derivative cash settlements paid (received)	(132,925)	(2,666)	7,056
Ending fair value of derivatives	118,400
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	153,099	17,673	24,148
Ending fair value of derivatives	118,427	153,099	17,673
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	25,715	101,813	(11,977)
Derivative cash settlements paid (received)	(91,953)	5,431	14,160
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	72,538	36,279	(1,554)
Derivative cash settlements paid (received)	$ (40,972)	$ (8,097)	$ (7,104)

Derivative Financial Instrume48

Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	$ 179,064	$ 223,778
Gross Amounts Offset in the Consolidated Balance Sheets	(58,980)	(70,679)
Net Amounts Presented in the Consolidated Balance Sheets	120,084	153,099
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(60,999)	(72,759)
Gross Amounts Offset in the Consolidated Balance Sheets	58,980	70,679
Net Amounts Presented in the Consolidated Balance Sheets	(2,019)	(2,080)
Commodity contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	177,082	223,778
Gross Amounts Offset in the Consolidated Balance Sheets	(58,655)	(70,679)
Net Amounts Presented in the Consolidated Balance Sheets	118,427	153,099
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(58,655)	(70,679)
Gross Amounts Offset in the Consolidated Balance Sheets	58,655	70,679
Net Amounts Presented in the Consolidated Balance Sheets	0	0
Interest rate contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	1,982	0
Gross Amounts Offset in the Consolidated Balance Sheets	(325)	0
Net Amounts Presented in the Consolidated Balance Sheets	1,657	0
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(2,344)	(2,080)
Gross Amounts Offset in the Consolidated Balance Sheets	325	0
Net Amounts Presented in the Consolidated Balance Sheets	$ (2,019)	$ (2,080)

Derivative Financial Instrume49

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details)	12 Months Ended
	Dec. 31, 2015USD ($)MMBTU$ / MMBTU$ / bblbbl
NYMEX WTI Swaps | Crude Oil | 2016
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	594,600
Average Price per Bbl ($ per Bbl)	68.37
NYMEX WTI Swaps | Crude Oil | 2016 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	56.15
NYMEX WTI Swaps | Crude Oil | 2016 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	99.85
NYMEX WTI Swaps | Crude Oil | 2017
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	182,500
Average Price per Bbl ($ per Bbl)	84.75
Price Range per Bbl ($ per Bbl)	84.75
Midland-to-Cushing Differential Swaps | Crude Oil | 2016
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	2,928,000
Average Price per Bbl ($ per Bbl)	1.60
Midland-to-Cushing Differential Swaps | Crude Oil | 2016 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	1.50
Midland-to-Cushing Differential Swaps | Crude Oil | 2016 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	1.75
Midland-to-Cushing Differential Swaps | Crude Oil | 2017
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	2,190,000
Average Price per Bbl ($ per Bbl)	0.30
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	0.05
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	0.75
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	621,300
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price	63.37
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price	88.37
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2016 | Call option | Short
Derivative [Line Items]
Average Strike Price	106.40
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	72,400
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price	60
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price	85
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Call option | Short
Derivative [Line Items]
Average Strike Price	104.20
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	183,000
Average Price per Bbl ($ per Bbl)	91.70
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	182,500
Average Price per Bbl ($ per Bbl)	90.85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018
Derivative [Line Items]
Derivative notional amount (bbl) | bbl	127,750
Average Price per Bbl ($ per Bbl)	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Put option | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX Henry Hub and Waha Swaps | Natural gas | 2016
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	29,019,200
Average Price per Bbl ($ per Bbl) | $ / MMBTU	3.40
NYMEX Henry Hub and Waha Swaps | Natural gas | 2016 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2016 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	5.30
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	27,600,000
Average Price per Bbl ($ per Bbl) | $ / MMBTU	3.36
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.39
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	27,600,000
Average Price per Bbl ($ per Bbl) | $ / MMBTU	3.36
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.39
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	25,800,000
Average Price per Bbl ($ per Bbl) | $ / MMBTU	3.36
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / MMBTU	3.39
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	5,580,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Put option | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2016 | Call option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.08
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	5,040,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Put option | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Call option | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.53
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps [Member] | Natural gas | 2016
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	14,977,818
Average Price per Bbl ($ per Bbl) | $ / MMBTU	0.19
Henry Hub NYMEX to San Juan Basin Differential Swaps | Natural gas | 2016
Derivative [Line Items]
Derivative notional amount (mmbtu) | MMBTU	2,499,780
Average Price per Bbl ($ per Bbl) | $ / MMBTU	0.16
Interest rate swaps | Libor Swap All Tranches [Member]
Derivative [Line Items]
Estimated Fair Market Value | $	$ (362,000)
Interest rate swaps | Libor Swap Tranche 1
Derivative [Line Items]
Notional Amount | $	$ 115,000,000
Weighted Average Fixed	0.85%
Estimated Fair Market Value | $	$ (27,000)
Interest rate swaps | Libor Swap Tranche 2
Derivative [Line Items]
Notional Amount | $	$ 235,000,000
Weighted Average Fixed	1.363%
Estimated Fair Market Value | $	$ (389,000)

Derivative Financial Instrume50

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements paid	$ (132,925)	$ (2,666)	$ 7,056
Ending fair value of derivatives	118,400
Interest rate swaps | Not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Beginning fair value of derivatives	(2,080)	(4,759)	(9,547)
Cash settlements paid	3,266	3,230	5,953
Ending fair value of derivatives	(362)	(2,080)	(4,759)
Interest rate swaps | Not designated as hedging instrument | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Total loss on interest rate swaps	$ (1,548)	$ (551)	$ (1,165)

Sales to Major Customers (Detai

Sales to Major Customers (Details) - Sales Revenue, Goods, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Enterprise (Teppco) Crude Oil, LP
Concentration Risk [Line Items]
Percentage of consolidated oil and natural gas revenue	6.00%	12.00%	17.00%
Plains Marketing, LP
Concentration Risk [Line Items]
Percentage of consolidated oil and natural gas revenue	7.00%	10.00%	7.00%

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in the ARO
Asset retirement obligation — beginning of period	$ 226,525	$ 175,786	$ 162,183
Liabilities incurred with properties acquired	60,526	50,487	10,969
Liabilities incurred with properties drilled	92	941	494
Liabilities settled during the period	(2,615)	(2,918)	(2,441)
Liabilities associated with properties sold	(9,386)	(5,891)	(1,606)
Current period accretion	11,263	8,120	6,187
Asset retirement obligation — end of period	$ 286,405	$ 226,525	$ 175,786

Asset Retirement Obligation Nar

Asset Retirement Obligation Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Revisions to previous estimates	$ 0	$ 0	$ 0

Partners' Equity - Preferred Un

Partners' Equity - Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	Jun. 04, 2015	Jul. 01, 2014	Jun. 17, 2014	Jun. 04, 2014	May. 12, 2014	Apr. 17, 2014	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Liquidation preference (in dollars per share)							$ 25
WPX acquisition
Class of Stock [Line Items]
Consideration transferred (in shares)				300,000
Conversion terms, minimum distribution per share				$ 0.90
WPX acquisition | Immediate vesting
Class of Stock [Line Items]
Consideration transferred (in shares)				100,000
WPX acquisition | Forfeiture, first two anniversaries
Class of Stock [Line Items]
Equity interests forfeiture (in shares)	66,666			66,666
WPX acquisition | Forfeiture, third anniversary
Class of Stock [Line Items]
Equity interests forfeiture (in shares)				66,668
WPX acquisition | Ratable vesting
Class of Stock [Line Items]
Consideration transferred (in shares)				10,000
Additional cash consideration				$ 35.5
Series A Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)						2,000,000
Dividend rate						8.00%
Share price (in dollars per share)						$ 25
Additional shares of underwriter purchase option (in shares)					300,000
Proceeds from offering								$ 55.2
Series A Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate							5.24%
Series B Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)			7,000,000
Dividend rate			8.00%
Share price (in dollars per share)			$ 25
Additional shares of underwriter purchase option (in shares)		200,000
Proceeds from offering								$ 174.3
Series B Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate							5.26%
Unvested IDUs | WPX acquisition
Class of Stock [Line Items]
Consideration transferred (in shares)				200,000

Partners' Equity - Income (loss

Partners' Equity - Income (loss) per unit (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Net loss	$ (701,541)	$ (283,645)	$ (35,272)
Distributions to preferred unitholders	(19,000)	(11,694)	0
Net loss attributable to unitholders	$ (720,541)	$ (295,339)	$ (35,272)
Weighted average number of units outstanding (in shares)	68,928,000	60,053,000	57,220,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	0
Weighted average unit and potential units outstanding (in shares)	68,928,000	60,053,000	57,220,000
Basic and diluted income (loss) per unit (in dollars per share)	$ (10.45)	$ (4.92)	$ (0.62)
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)	550,447	254,183	234,686
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)	862,064	323,965	189,143

Unit-Based Compensation - LTIP

Unit-Based Compensation - LTIP and Unit Appreciation Rights (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 15, 2006
Unit option awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	0	0	0
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 2,700,000	$ 2,300,000	$ 2,300,000
Unrecognized compensation costs	$ 5,100,000
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 3 months 21 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 3,400,000	$ 2,300,000	$ 1,200,000
Unit appreciation rights (UARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other than options granted (in shares)	301,020	243,274	234,156
Unit award expiration period	7 years	7 years	7 years
Share-based compensation expense	$ (10,700)	$ (1,260,000)	$ 864,300
Unrecognized compensation costs	$ 374
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 7 months 28 days
Volatility	59.00%	38.00%	50.00%
Share based compensation, forfeiture rate	5.30%
Annual distribution rate per unit (in dollars per share)	$ 0.60	$ 2.44	$ 2.34
Annual interest rate	1.70%	1.60%	1.40%
Unit appreciation rights (UARs) | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other than options granted (in shares)	204,500	136,100	156,650
Award vesting period	3 years	3 years	3 years
Unit appreciation rights (UARs) | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other than options granted (in shares)	96,520	105,174	77,506
Award vesting period	3 years	3 years	3 years
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units authorized for issuance (in shares)				5,000,000
Units issued as compensation (in shares)	2,229,157
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)	904,551
Long Term Incentive Plan | Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	862,064
Long Term Incentive Plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	196,528

Unit-Based Compensation - UAR A

Unit-Based Compensation - UAR Activity (Details) - Unit appreciation rights (UARs) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Units (in shares)
Outstanding	671,229	627,043	516,219
Granted	301,020	243,274	234,156
Exercised		(137,252)	(96,166)
Forfeited	(36,133)	(61,836)	(27,166)
Outstanding	936,116	671,229	627,043
Options and UARs exercisable	372,049	220,056	240,288
Weighted-Average Exercise Price (in dollars per share)
Outstanding	$ 26.97	$ 25.99	$ 24.71
Granted	6.49	28.21	26.53
Exercised		24.35	20.21
Forfeited	21.07	27.27	26.74
Outstanding	20.61	26.97	25.99
Options and UARs exercisable	$ 26.45	$ 25.50	$ 24.02
Weighted-Average Remaining Contractual Term
Outstanding	4 years 10 months 28 days	5 years 1 month 25 days	5 years 1 month 28 days
Options and UARs exercisable	3 years 3 months 10 days	3 years 6 months 5 days	3 years 9 months 20 days
Aggregate Intrinsic Value
Outstanding	$ 0	$ 0	$ 1,518,416
Options and UARs exercisable	$ 0	$ 0	$ 1,061,542

Unit-Based Compensation - Statu

Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details) - Unit appreciation rights (UARs)	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of Units
Non-vested at January 1, 2015 | shares	451,173
Granted | shares	301,020
Vested | shares	(151,993)
Forfeited | shares	(36,133)
Non-vested at December 31, 2015 | shares	564,067
Weighted- Average Exercise Price
Non-vested at January 1, 2015 | $ / shares	$ 27.69
Granted | $ / shares	6.49
Vested | $ / shares	27.84
Forfeited | $ / shares	21.07
Non-vested at December 31, 2015 | $ / shares	$ 16.76

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - Unit appreciation rights (UARs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	4 years 10 months 28 days	5 years 1 month 25 days	5 years 1 month 27 days
Annual interest rate	1.70%	1.60%	1.40%
Annual distribution rate per unit (in dollars per share)	$ 0.60	$ 2.44	$ 2.34
Volatility	59.00%	38.00%	50.00%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details) $ / shares in Units, $ in Millions	Jun. 15, 2015$ / sharesshares	May. 15, 2014director$ / sharesshares	May. 14, 2013director$ / sharesshares	Mar. 31, 2015shares	Mar. 31, 2014shares	Feb. 28, 2013officershares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)							550,447	254,183	234,686
Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Individuals eligible for plan | officer						5
Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of each unit at issuance (in dollars per share) | $ / shares	$ 9.13	$ 27.50
Subjective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				341,251	117,197	46,430
Objective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				259,998	102,572	76,723
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense | $							$ 3.4	$ 2.3	$ 1.2
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense | $							2.7	$ 2.3	$ 2.3
Unrecognized compensation costs | $							$ 5.1
Unrecognized compensation costs, period of recognition							2 years 3 months 21 days
Restricted stock units (RSUs) | Non-executive employees and certain executives
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)									85,728
Restricted stock units (RSUs) | Non-executive employees and certain executives | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									3 years
Restricted stock units (RSUs) | Non-executive employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)							381,860	127,845
Restricted stock units (RSUs) | Non-executive employees | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period								3 years
Restricted stock units (RSUs) | Executive Employee [Member] | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period							3 years
Restricted stock units (RSUs) | Executive Employee [Member] | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period							5 years
Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of each unit at issuance (in dollars per share) | $ / shares			$ 27.39
Unrestricted units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	11,025	3,628	3,715
Individuals eligible for plan | director		5	5

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details)	11 Months Ended
	May. 08, 2014offering	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	May. 13, 2014USD ($)	May. 28, 2013USD ($)
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,458,000,000	$ 959,000,000
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Number of private offerings | offering	2
Long-term debt, gross		$ 550,000,000	$ 550,000,000	$ 300,000,000	$ 250,000,000
Senior notes | 2020 and 2021 Senior Notes
Debt Instrument [Line Items]
Percent of guarantee by subsidiaries owned		100.00%

Subsequent Events (Details)

Subsequent Events (Details)	Feb. 19, 2016USD ($)	Jan. 21, 2016	Jun. 17, 2014	Apr. 17, 2014	Feb. 22, 2016USD ($)	Dec. 31, 2015USD ($)
Series A Preferred Equity
Subsequent Event [Line Items]
Dividend rate				8.00%
Series B Preferred Equity
Subsequent Event [Line Items]
Dividend rate			8.00%
Subsequent Event | Series A Preferred Equity
Subsequent Event [Line Items]
Dividend rate		8.00%
Subsequent Event | Series B Preferred Equity
Subsequent Event [Line Items]
Dividend rate		8.00%
Senior notes | Subsequent Event
Subsequent Event [Line Items]
Face amount of repurchased debt					$ 104,500,000
Revolving Credit Facility
Subsequent Event [Line Items]
Current borrowing capacity						$ 900,000,000
Ratio of EBITDA to interest expense, minimum						2.5
Ratio of indebtedness to EBITDA						2.5
Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Current borrowing capacity	$ 725,000,000
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Ratio of Indebtedness to EBITDA, maximum trigger to increase basis spread	3
Maximum liquid financial assets threshold to trigger payment	$ 20,000,000
Maximum oil and gas properties managed as collateral security	90.00%
Dividend payment minimum unused commitments	15.00%
Dividend payment maximum indebtedness to EBITDA ratio	4
Redemption or repurchase of securities, minimum unused commitments percentage	15.00%
Redemption or repurchase of securities, minimum indebtedness to EBITDA ratio	4
Debt redemption or repurchase of debt, minimum unused commitments percentage	20.00%
Debt redemption or repurchase of debt, minimum unused commitments	$ 100,000,000
Redemption or repurchase of debt using proceeds form sale of property, time period after sale	90 years
Redemption or repurchase of debt using proceeds from sale of property, maximum percentage of property	50.00%
Redemption or repurchase of debt using proceeds from sale of property, maximum percentage of debt	50.00%
Redemption or repurchase of debt using proceeds from sale of property, maximum sales proceeds	$ 75,000,000
Exchange of debt, maximum aggregate principal amount	$ 400,000,000
Exchange of debt, minimum scheduled maturity period	120 years
Current borrowing capacity	$ 725,000,000
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Subsequent Event | Debt Covenant, Period One
Subsequent Event [Line Items]
Redemption or repurchase of debt, maximum indebtedness to EBITDA ratio	3
Ratio of EBITDA to interest expense, minimum	2.50
Ratio of indebtedness to EBITDA	3.50
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Subsequent Event | Debt Covenant, Period Two
Subsequent Event [Line Items]
Redemption or repurchase of debt, maximum indebtedness to EBITDA ratio	2.50
Ratio of EBITDA to interest expense, minimum	2
Ratio of indebtedness to EBITDA	3.25
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Subsequent Event | Debt Covenant, Period Three
Subsequent Event [Line Items]
Ratio of EBITDA to interest expense, minimum	2.50
Ratio of indebtedness to EBITDA	3
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Subsequent Event | Debt Covenant, Period Four
Subsequent Event [Line Items]
Ratio of indebtedness to EBITDA	2.50
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Maximum | Subsequent Event
Subsequent Event [Line Items]
Potential increase in basis spread	0.50%
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Eurodollar | Minimum | Subsequent Event
Subsequent Event [Line Items]
Basis spread on variable rate	2.00%
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Eurodollar | Maximum | Subsequent Event
Subsequent Event [Line Items]
Basis spread on variable rate	3.00%
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Alternate Base Rate | Minimum | Subsequent Event
Subsequent Event [Line Items]
Basis spread on variable rate	1.00%
Revolving Credit Facility | Seventh Amendment the Current Credit Agreement | Alternate Base Rate | Maximum | Subsequent Event
Subsequent Event [Line Items]
Basis spread on variable rate	2.00%