Legacy Reserves 10-K 22 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 21, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	LEGACY RESERVES LP
Entity Central Index Key	1,358,831
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		72,625,147
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 117.3

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash	$ 2,555	$ 2,006
Accounts receivable, net:
Oil and natural gas	43,192	33,944
Joint interest owners	23,414	25,378
Other	2	86
Fair value of derivatives	6,162	63,711
Prepaid expenses and other current assets	7,447	4,334
Total current assets	82,772	129,459
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting	3,305,856	3,485,634
Unproved properties	13,448	13,424
Accumulated depletion, depreciation, amortization and impairment	(2,137,395)	(2,090,102)
Total oil and natural gas properties, net	1,181,909	1,408,956
Other property and equipment, net of accumulated depreciation and amortization of $10,412 and $8,915, respectively	3,423	4,575
Operating rights, net of amortization of $5,369 and $4,953, respectively	1,648	2,064
Fair value of derivatives	20,553	56,373
Other assets	8,874	11,047
Investments in equity method investees	647	646
Total assets	1,299,826	1,613,120
Current liabilities:
Accounts payable	9,092	13,581
Accrued oil and natural gas liabilities	53,248	50,573
Fair value of derivatives	9,743	2,019
Asset retirement obligation	2,980	3,496
Other	11,546	11,424
Total current liabilities	86,609	81,093
Long-term debt	1,161,394	1,427,614
Asset retirement obligation	269,168	282,909
Fair value of derivatives	4,091	0
Other long-term liabilities	643	1,181
Total liabilities	1,521,905	1,792,797
Commitments and contingencies
Partners’ equity (deficit):
Limited partners' deficit - 72,056,097 and 68,949,961 units issued and outstanding at December 31, 2016 and 2015, respectively	(482,200)	(439,811)
General partner’s deficit (approximately 0.03%)	(146)	(133)
Total partners’ deficit	(222,079)	(179,677)
Total liabilities and partners’ deficit	1,299,826	1,613,120
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2016 and December 31, 2015
Partners’ equity (deficit):
Incentive distribution equity	30,814	30,814
Total partners’ deficit	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2016 and December 31, 2015
Partners’ equity (deficit):
Preferred equity	55,192	55,192
Total partners’ deficit	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2016 and December 31, 2015
Partners’ equity (deficit):
Preferred equity	174,261	174,261
Total partners’ deficit	$ 174,261	$ 174,261

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Other property and equipment, accumulated depreciation and amortization	$ 10,412	$ 8,915
Operating rights, amortization	$ 5,369	$ 4,953
Limited partners' equity, units issued (in shares)	72,056,097	68,949,961
Limited partners' equity, units outstanding (in shares)	72,056,097	68,949,961
General partner's equity, percent	0.03%	0.03%
Incentive Distribution Equity
Incentive distribution equity, units issued (in shares)	100,000	100,000
Incentive distribution equity, units outstanding (in shares)	100,000	100,000
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil sales	$ 152,507	$ 199,841	$ 396,774
Natural gas liquids (NGL) sales	15,406	16,645	27,483
Natural gas sales	146,444	122,293	108,042
Total revenues	314,357	338,779	532,299
Expenses:
Oil and natural gas production	179,333	194,491	198,801
Production and other taxes	14,267	16,383	31,534
General and administrative	43,639	46,511	38,980
Depletion, depreciation, amortization and accretion	150,414	177,258	173,686
Impairment of long-lived assets	61,796	633,805	448,714
Gain on disposal of assets	(50,095)	(3,972)	(2,479)
Total expenses	399,354	1,064,476	889,236
Operating loss	(84,997)	(725,697)	(356,937)
Other income (expense):
Interest income	67	329	873
Interest expense	(79,060)	(76,891)	(67,218)
Gain on extinguishment of debt	150,802	0	0
Equity in income of equity method investees	0	126	428
Net gains (losses) on commodity derivatives	(41,224)	98,253	138,092
Other	(179)	841	258
Loss before income taxes	(54,591)	(703,039)	(284,504)
Income tax (expense) benefit	(1,229)	1,498	859
Net loss	(55,820)	(701,541)	(283,645)
Distributions to preferred unitholders	(19,000)	(19,000)	(11,694)
Net loss attributable to unitholders	$ (74,820)	$ (720,541)	$ (295,339)
Loss per unit — basic and diluted (in dollars per share)	$ (1.06)	$ (10.45)	$ (4.92)
Weighted average number of units used in computing net loss per unit —
Basic and Diluted (in shares)	70,605	68,928	60,053

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	Limited PartnerPreferred Units	General Partner
Unitholders equity, beginning balance (in shares) at Dec. 31, 2013			0		0	0	57,280
Unitholders equity, beginning balance at Dec. 31, 2013	$ 510,396		$ 0		$ 0	$ 0	$ 510,322			$ 74
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued 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	$ 0
Vesting of restricted and phantom units (in shares)							113
Issuance of units, net (in shares)							11,500
Issuance of units, net	303,457						$ 303,457
Incentive Distribution Units issued in exchange for oil and natural gas properties (in shares)			100
Incentive Distribution Units issued in exchange for oil and natural gas properties	30,814		$ 30,814
Distributions to preferred unitholders	(11,694)						(11,694)
Distributions to unitholders, $2.405, $1.46, and $0 per unit for the years ended December 31, 2014, 2015, and 2016, 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 for services (in shares)								66
Units issued for services	5,858	604					$ 5,858	$ 604
Vesting of restricted and phantom units (in shares)							78
Issuance of units, net	(103)						$ (103)
Incentive Distribution Units issued in exchange for oil and natural gas properties (in shares)							(105)
Incentive Distribution Units issued in exchange for oil and natural gas properties	(1,349)						$ (1,349)
Distributions to preferred unitholders	(19,000)						(19,000)
Distributions to unitholders, $2.405, $1.46, and $0 per unit for the years ended December 31, 2014, 2015, and 2016, 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)
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued for services (in shares)								237
Units issued for services	6,252	$ 614					$ 6,252	$ 614
Vesting of restricted and phantom units (in shares)							150
Units issued in exchange for retirement of debt (in shares)							2,719
Units issued in exchange for retirement of debt	6,607						$ 6,607
Distributions to unitholders, $2.405, $1.46, and $0 per unit for the years ended December 31, 2014, 2015, and 2016, respectively	(55)						(55)
Net loss	(55,820)						$ (55,807)			(13)
Unitholders equity, ending balance (in shares) at Dec. 31, 2016			100		2,300	7,200	72,056
Unitholders equity, ending balance at Dec. 31, 2016	$ (222,079)		$ 30,814		$ 55,192	$ 174,261	$ (482,200)			$ (146)

Consolidated Statements of Uni6

Consolidated Statements of Unitholders Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Partners' Capital [Abstract]
Distributions to unitholders (in dollars per share)	$ 0	$ 1.46	$ 2.405

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net loss	$ (55,820)	$ (701,541)	$ (283,645)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depletion, depreciation, amortization and accretion	150,414	177,258	173,686
Amortization of debt discount and issuance costs	10,319	5,532	4,637
Gain on extinguishment of debt	(150,802)	0	0
Impairment of long-lived assets	61,796	633,805	448,714
(Gain) loss on derivatives	40,679	(99,971)	(140,771)
Equity in income of equity method investees	0	(126)	(428)
Distribution from equity method investee	0	191	1,467
Unit-based compensation	7,035	6,451	2,089
Gain on disposal of assets	(50,095)	(3,972)	(2,479)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	(9,248)	15,447	(1,962)
(Increase) decrease in accounts receivable, joint interest owners	1,964	(9,143)	297
Decrease in accounts receivable, other	84	151	389
(Increase) decrease in other assets	(940)	333	(1,193)
Increase (decrease) in accounts payable	(4,489)	10,794	(3,228)
Increase (decrease) in accrued oil and natural gas liabilities	2,675	(28,042)	15,454
Decrease in other liabilities	(3,882)	(5,121)	(5,811)
Total adjustments	55,510	703,587	490,861
Net cash (used in) provided by operating activities	(310)	2,046	207,216
Cash flows from investing activities:
Investment in oil and natural gas properties	(41,496)	(577,186)	(638,942)
Proceeds from sale of assets	97,416	69,118	5,334
Investment in other equipment	(436)	(2,277)	(1,472)
Net cash settlements on commodity derivatives	64,505	132,925	2,666
Net cash provided by (used in) investing activities	119,989	(377,420)	(632,414)
Cash flows from financing activities:
Proceeds from long-term debt	266,000	840,000	1,333,000
Payments of long-term debt	(376,402)	(341,000)	(1,275,000)
Payments of debt issuance costs	(8,728)	(1,891)	(10,005)
Proceeds from issuance of limited partner interests, net	0	(103)	532,910
Distributions to unitholders	0	(120,351)	(157,566)
Net cash (used in) provided by financing activities	(119,130)	376,655	423,339
Net increase (decrease) in cash	549	1,281	(1,859)
Cash, beginning of period	2,006	725	2,584
Cash, end of period	2,555	2,006	725
Non-Cash Investing and Financing Activities:
Asset retirement obligation costs and liabilities	1	92	941
Asset retirement obligations associated with property acquisitions	24	60,526	50,487
Asset retirement obligations associated with properties sold	(24,605)	(9,386)	(5,891)
Units acquired in exchange for investment in equity method investee	0	(1,349)	0
Units issued in exchange for Senior Notes	6,607	0	0
Incentive Distribution units issued in exchange for oil and natural gas properties	$ 0	$ 0	$ 30,814

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies (a) Organization, Basis of Presentation and Description of Business Legacy Reserves LP (“LRLP,” “Legacy” or the “Partnership”) and 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, 2016 , Legacy recognized $61.8 million of impairment expense in 43 separate producing fields, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016 , which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2015 , Legacy recognized $633.8 million of impairment expense, $598.1 million 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. 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. Legacy did not recognize impairment expense on unproved properties during the year ended December 31, 2016. During the years ended December 31, 2015 and 2014 , Legacy recognized $35.7 million and $35.0 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 $(1.2) million , $1.5 million and $0.9 million for the years ended December 31, 2016 , 2015 and 2014 , 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 $1.3 billion at December 31, 2016 . (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. 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, 2016 , 2015 and 2014 . (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 2017, 2018, 2019, 2020 and 2021 are $396,000 , $358,000 , $349,000 , $322,000 and $223,000 , 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) 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. (n) 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, 2016 , do not include 484,447 units related to unvested restricted unit awards. (o) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of December 31, 2016 and 2015 . December 31, 2016 2015 (In thousands) Revenue payable to joint interest owners $ 19,576 $ 15,253 Accrued lease operating expense 17,696 19,007 Accrued capital expenditures 7,019 2,881 Accrued ad valorem tax 5,300 8,723 Other 3,657 4,709 $ 53,248 $ 50,573 (p) Restricted Cash Restricted cash of $3.6 million as of December 31, 2016 is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. There was no restricted cash recorded at December 31, 2015 . (q) Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K. Please read "—Footnote 3—Long-Term Debt" for further discussion regarding this reclassification. (r) Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our business and comparing historical accounting policies and practices to the new standard. Our contracts are primarily short-term in nature, and our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our financial statements upon adoption.

Fair Values of Financial Instru

Fair Values of Financial Instruments	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Values of Financial Instruments	Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments 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 carrying amount of the second lien term loan debt under Legacy’s term loan credit agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar 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 $179.4 million and $302.0 million , respectively, as of December 31, 2016 . 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, 2016 and 2015 : 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) $ — $ (224 ) $ — $ (224 ) Oil and natural gas derivatives — 12,690 8 12,698 Interest rate swaps — 183 — 183 Total as of December 31, 2016 $ — $ 12,649 $ 8 $ 12,657 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 ____________________ (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 costless collars, 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, 2016 2015 2014 (In thousands) Beginning balance $ (4,493 ) $ 555 $ 20,615 Total gains (losses) 253 (10,029 ) (6,185 ) Settlements 4,248 4,981 677 Transfers — — (14,552 ) (a) Ending balance $ 8 $ (4,493 ) $ 555 Gains included in earnings relating to derivatives still held as of December 31, 2016, 2015 and 2014 $ 68 $ (4,493 ) $ 555 (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 were transferred to Level 2 instruments. 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 ARO is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2016 and 2015 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) 2016 Impairment(a) $ — $ — $ 60,729 Acquisitions(b) $ — $ — $ 11,998 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 ____________________ (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, 2016 , Legacy incurred impairment charges of $61.8 million as oil and natural gas properties with a net cost basis of $122.5 million were written down to their fair value of $60.7 million . 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 . 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 was related to unproved properties acquired since 2010 that were no longer viable. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2016 , Legacy acquired oil and natural gas properties with a fair value of $12.0 million in 3 immaterial transactions, both individually and in the aggregate. 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 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, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following at December 31, 2016 and 2015 : December 31, 2016 2015 (In thousands) Credit Facility due 2019 $ 463,000 $ 608,000 Second Lien Term Loans due 2020 60,000 — 8% Senior Notes due 2020 232,989 300,000 6.625% Senior Notes due 2021 432,656 550,000 1,188,645 1,458,000 Unamortized discount on Second Lien Term Loans and Senior Notes (12,802 ) (17,604 ) Unamortized debt issuance costs (a) (14,449 ) (12,782 ) Total long term debt $ 1,161,394 $ 1,427,614 ____________________ (a) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs are now recorded as a direct deduction from the carrying amount of debt. As such, debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or retained earnings. Credit Facility 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 95% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the 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, 2016 was set at $600 million . 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. Effective October 25, 2016, Legacy entered into an amendment (the “Eighth Amendment”) to the Current Credit Agreement with the Administrative Agent and certain other financial institutions party thereto as lenders to, among other items: (i) permit the issuance and use of the Second Lien Term Loans pursuant to the Second Lien Term Loan Credit Agreement (as defined below), (ii) increase the percentage of the total value of Legacy’s Oil and Gas Properties required to be subject to a mortgage to 95% of the value or the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin, (iii) require Legacy to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions and (iv) allow Legacy to hedge on an unsecured basis with counterparties who (or whose credit support provider) has an issuer rating or whose long term senior unsecured debt rating of BBB-/Baa3. The Current Credit Agreement, as amended by the Eighth Amendment, also contains covenants that, among other things, require Legacy to maintain specified ratios or conditions. As of December 31, 2016 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 4.5 to 1.0 beginning with the fiscal quarter ending on December 31, 2018, (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 2.0 to 1.0, (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 and (iv) the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at 10 percent per annum, of Legacy’s proved developed producing oil and gas properties (“PDP PV-10”) as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents, in each case as of such date to (b) Secured Debt as of such day to be equal to or less than 1.00 to 1.00 beginning with the fiscal quarter ending June 30, 2017. All capitalized terms not defined in the foregoing description have the meaning assigned to them in the Current Credit Agreement Amendment, as amended by the Eighth Amendment. As of December 31, 2016 , Legacy had outstanding borrowings of $463 million under the Current Credit Agreement at a weighted average interest rate of 3.91% . Thus, Legacy had approximately $135.1 million of borrowing availability remaining. As of February 21, 2017 , Legacy had approximately $134.1 million of borrowing availability remaining. For the year ended December 31, 2016 , Legacy paid $19.0 million of interest expense on the Current Credit Agreement. At December 31, 2016 , Legacy was in compliance with all covenants contained in the Current Credit Agreement. Depending on future oil and natural gas prices, 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, 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 Second Lien Term Loans (as defined below), 2020 Senior Notes and 2021 Senior Notes, to be immediately due and payable. Second Lien Term Loans On October 25, 2016, Legacy entered into a Term Loan Credit Agreement (the “Second Lien Term Loan Credit Agreement”) among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, providing for term loans up to an aggregate principal amount of $300.0 million (the “Second Lien Term Loans”). GSO Capital Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Current Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Current Credit Agreement. Legacy used the initial $60.0 million of gross loan proceeds from its Second Lien Term Loan to repay outstanding indebtedness and pay associated transaction expenses. Additional Second Lien Term Loans up to an aggregate amount of $240.0 million are available at Legacy’s discretion for twelve months following the date of the Second Lien Term Loan Credit Agreement. The Second Lien Term Loans under the Second Lien Term Loan Credit Agreement will be issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash or, prior to the 18 month anniversary of the Second Lien Term Loan Credit Agreement, Legacy may elect to pay in kind up to 50% of the interest payable. The Second Lien Term Loans may be used for general corporate purposes and for the repayment of outstanding indebtedness, in any case as may be approved by Legacy and GSO. For the first 24 months following the effective date of the Term Loan Credit Agreement, GSO may not assign more than 49% of the Second Lien Term Loans without the Partnership's consent. The Second Lien Term Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Second Lien Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Second Lien Term Loan Credit Agreement will mature on August 1, 2020. The Second Lien Term Loan Credit Agreement contains customary prepayment provisions and make-whole premiums. Legacy will pay a quarterly fee of 0.250% on the average daily amount of the unused commitments under the Term Loan Credit Agreement. The Second Lien Term Loan Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows: • not permit, beginning with the fiscal quarter ending June 30, 2017, the ratio of the sum of (i) PDP PV-10, (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than 1.00 to 1.00; • not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than 4.50 to 1.00; • within a certain period of time after the date of the Second Lien Term Loan Credit Agreement, enter into hedging transactions covering at least 75% of the projected oil and natural gas production from Proved Developed Producing Properties for each month until the two year anniversary of the Second Lien Term Loan Credit Agreement; • Legacy is required to mortgage 95% of the total value of all of its Oil and Gas Properties set forth in the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin; and • require us to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions. All capitalized terms used but not defined in the foregoing description have the meaning assigned to them in the Second Lien Term Loan Credit Agreement. For the year ended December 31, 2016 , Legacy paid cash interest expense of $1.4 million under the Second Lien Term Loan Credit Agreement. 8% Senior Notes Due 2020 On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300.0 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 has 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 % 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, 2016 , 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. During the year ended December 31, 2016, Legacy repurchased a face amount of $52.0 million of its 2020 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. On June 1, 2016, Legacy exchanged 2,719,124 units representing limited partner interests in the Partnership for $15.0 million of face amount of its outstanding 2020 Senior Notes. Legacy treated this exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on June 1, 2016. 6.625% Senior Notes Due 2021 On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of 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. 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, 2016 , 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. During the year ended December 31, 2016, Legacy repurchased a face amount of $117.3 million of its 2021 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. For the year ended December 31, 2016 , Legacy paid $47.9 million of cash interest expense for the 2020 Senior Notes and 2021 Senior Notes.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
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 $337.2 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 $ 461,306 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 433,955 Pro Forma Operating Results The following table reflects the unaudited pro forma results of operations as though the 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 (In thousands) Revenues $ 380,619 $ 687,829 Net loss attributable to unitholders $ (713,364 ) $ (243,197 ) Loss per unit — basic and diluted $ (10.35 ) $ (4.05 ) Units used in computing loss per unit: Basic 68,928 60,053 Diluted 68,928 60,053 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, 2016 2015 2014 WPX Acquisition (In thousands) Revenues $ 62,522 $ 69,504 $ 48,470 Excess of revenues over direct operating expenses $ 23,622 $ 22,324 $ 22,333 Anadarko Acquisitions Revenues $ 51,177 $ 22,881 $ — Excess of revenues over direct operating expenses $ 23,319 $ 12,373 $ —

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown and Dale A. Brown, directors of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $98,297 , $382,629 and $84,470 in 2016, 2015 and 2014, respectively to Blue Quail for such services. 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. 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 $111,299 without respect to property taxes and insurance. The lease expires in September 2020.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy is party to a contractual agreement, extending through 2022, to purchase CO 2 volumes from a third party. The contract requires Legacy to purchase minimum annual volumes, the pricing of which is calculated as a percentage of NYMEX-WTI oil prices, with a floor of $57.14 . Based upon the minimum required volumes and the NYMEX-WTI strip prices as of December 31, 2016 , we estimate the value of our total future obligation to be approximately $48.6 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 and retention bonus agreements with its officers and certain other employees. The employment agreements with its officers specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively. The retention bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control.

Business and Credit Concentrati

Business and Credit Concentrations	12 Months Ended
	Dec. 31, 2016
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 2016 , 2015 or 2014 . 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, costless collars 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, 2016 , Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $12.7 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 years ended December 31, 2016 and 2015 , Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the year ended December 31, 2014 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2016 2015 2014 Enterprise (Teppco) Crude Oil, LP 1% 6% 12% Plains Marketing, LP 6% 7% 10%

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments 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 carrying amount of the second lien term loan debt under Legacy’s term loan credit agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar 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 $179.4 million and $302.0 million , respectively, as of December 31, 2016 . 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, 2016 and 2015 : 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) $ — $ (224 ) $ — $ (224 ) Oil and natural gas derivatives — 12,690 8 12,698 Interest rate swaps — 183 — 183 Total as of December 31, 2016 $ — $ 12,649 $ 8 $ 12,657 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 ____________________ (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 costless collars, 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, 2016 2015 2014 (In thousands) Beginning balance $ (4,493 ) $ 555 $ 20,615 Total gains (losses) 253 (10,029 ) (6,185 ) Settlements 4,248 4,981 677 Transfers — — (14,552 ) (a) Ending balance $ 8 $ (4,493 ) $ 555 Gains included in earnings relating to derivatives still held as of December 31, 2016, 2015 and 2014 $ 68 $ (4,493 ) $ 555 (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 were transferred to Level 2 instruments. 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 ARO is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2016 and 2015 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) 2016 Impairment(a) $ — $ — $ 60,729 Acquisitions(b) $ — $ — $ 11,998 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 ____________________ (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, 2016 , Legacy incurred impairment charges of $61.8 million as oil and natural gas properties with a net cost basis of $122.5 million were written down to their fair value of $60.7 million . 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 . 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 was related to unproved properties acquired since 2010 that were no longer viable. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2016 , Legacy acquired oil and natural gas properties with a fair value of $12.0 million in 3 immaterial transactions, both individually and in the aggregate. 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 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, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Commodity derivative transactions Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes. 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. The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2016 , 2015 , and 2014 . December 31, 2016 2015 2014 (In thousands) Beginning fair value of commodity derivatives $ 118,427 $ 153,099 $ 17,673 Total gain (loss) crude oil derivatives (9,410 ) 25,715 101,813 Total gain (loss) natural gas derivatives (31,814 ) 72,538 36,279 Crude oil derivative cash settlements paid (received) (37,464 ) (91,953 ) 5,431 Natural gas derivative cash settlements received (27,041 ) (40,972 ) (8,097 ) Ending fair value of commodity derivatives $ 12,698 $ 118,427 $ 153,099 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, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 56,103 $ (30,648 ) $ 25,455 Interest rate derivatives 1,328 (68 ) 1,260 Total derivative assets $ 57,431 $ (30,716 ) $ 26,715 Offsetting Derivative Liabilities: Commodity derivatives $ (43,405 ) $ 30,648 $ (12,757 ) Interest rate derivatives (1,145 ) 68 (1,077 ) Total derivative liabilities $ (44,550 ) $ 30,716 $ (13,834 ) December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 ) As of December 31, 2016 , 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 2017 182,500 $84.75 $84.75 2018 730,000 $55.04 $55.00 - $55.15 As of December 31, 2016 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2017 2,190,000 $(0.30) $(0.75) - $(0.05) As of December 31, 2016 , Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below: Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl 2017 2,190,000 $45.00 $59.02 2018 1,095,000 $45.83 $59.97 As of December 31, 2016 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2017 72,400 $60.00 $85.00 $104.20 As of December 31, 2016 , 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 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of December 31, 2016 , 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 Price Range Calendar Year Volumes (MMBtu) Price per MMBtu per MMBtu 2017 27,600,000 $3.36 $3.29 - $3.39 2018 42,200,000 $3.25 $3.04 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39 As of December 31, 2016 , Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below: Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu 2017 14,600,000 $2.90 $3.44 As of December 31, 2016 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu 2017 5,040,000 $3.75 $4.25 $5.53 As of December 31, 2016 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, SoCal 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: 2017 Average Volumes (MMBtu) Price per MMBtu NWPL 7,300,000 $(0.16) SoCal 2,500,250 $0.11 San Juan 2,500,250 $(0.10) Interest rate derivative transactions Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in overhedged amounts. Legacy 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, 2016 2015 2014 (In thousands) Beginning fair value of interest rate swaps $ (362 ) $ (2,080 ) $ (4,759 ) Total loss on interest rate swaps (2,108 ) (1,548 ) (551 ) Cash settlements paid 2,653 3,266 3,230 Ending fair value of interest rate swaps $ 183 $ (362 ) $ (2,080 ) The table below summarizes the interest rate swap assets and liabilities as of December 31, 2016 . Weighted Average Fixed Effective Maturity Estimated Fair Market Value at December 31, Notional Amount Rate Date Date 2016 (Dollars in thousands) $115,000 0.850 % 9/1/2015 9/1/2017 (11 ) $235,000 1.363 % 9/1/2015 9/1/2019 194 Total fair value of interest rate derivatives $ 183

Sales to Major Customers

Sales to Major Customers	12 Months Ended
	Dec. 31, 2016
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 2016 , 2015 or 2014 . 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, costless collars 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, 2016 , Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $12.7 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 years ended December 31, 2016 and 2015 , Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the year ended December 31, 2014 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2016 2015 2014 Enterprise (Teppco) Crude Oil, LP 1% 6% 12% Plains Marketing, LP 6% 7% 10%

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2016
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 ARO 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, 2016 , 2015 and 2014 . December 31, 2016 2015 2014 (In thousands) Asset retirement obligation — beginning of period $ 286,405 $ 226,525 $ 175,786 Liabilities incurred with properties acquired 24 60,526 50,487 Liabilities incurred with properties drilled 1 92 941 Liabilities settled during the period (2,351 ) (2,615 ) (2,918 ) Liabilities associated with properties sold (24,605 ) (9,386 ) (5,891 ) Current period accretion 12,674 11,263 8,120 Asset retirement obligation — end of period $ 272,148 $ 286,405 $ 226,525 Each year the Partnership reviews and, to the extent necessary, revises its ARO estimates. During 2014 , 2015 and 2016 , no revisions of previous estimates were deemed necessary.

Partners' Equity

Partners' Equity	12 Months Ended
	Dec. 31, 2016
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. As of December 31, 2016 , $1.92 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $18.2 million . Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of 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. 66,666 unvested IDUs were forfeited on each of June 4, 2015 and June 4, 2016. 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, 2016 2015 2014 (In thousands) Net loss $ (55,820 ) $ (701,541 ) $ (283,645 ) Distributions to preferred unitholders (19,000 ) (19,000 ) (11,694 ) Net loss attributable to unitholders $ (74,820 ) $ (720,541 ) $ (295,339 ) Weighted average number of units outstanding 70,605 68,928 60,053 Effect of dilutive securities: Restricted and phantom units — — — Weighted average units and potential units outstanding 70,605 68,928 60,053 Basic and diluted loss per unit $ (1.06 ) $ (10.45 ) $ (4.92 ) As of December 31, 2016 , 484,447 restricted units and 1,212,692 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, 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. 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.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2016
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, 2016 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 2,926,889 units have been made, comprised of 266,014 unit option awards, 1,014,499 restricted unit awards, 1,212,692 phantom unit awards and 433,684 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 units 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 until settlement. 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 accounts for the UARs under the liability method. 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. Legacy did not issue UARs to employees during the year ended December 31, 2016 . All of the UARs granted in 2015 and 2014 expire seven years from the grant date and are exercisable when they vest. For the years ended December 31, 2016 , 2015 and 2014 , Legacy recorded compensation expense (benefit) of $223.6 thousand , $(10.7) thousand and $(1,260.0) 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, 2016 , 2015 and 2014 fair value of these UARs (see Note 8). As of December 31, 2016 , there was a total of $129,093 of unrecognized compensation costs related to the unexercised and non-vested portion of the UARs. At December 31, 2016 , this cost was expected to be recognized over a weighted-average period of 1.59 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 87% and employed the Black-Scholes model to estimate the December 31, 2016 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 $0.00 per unit. A summary of UAR activity for the year ended December 31, 2016 , 2015 and 2014 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value 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 $ — Outstanding at January 1, 2016 936,116 $ 20.61 Expired (21,067 ) $ 16.07 Forfeited (30,503 ) $ 19.80 Outstanding at December 31, 2016 884,546 $ 20.75 3.68 $ — UARs exercisable at December 31, 2016 570,369 $ 24.38 2.77 $ — The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2016 : Non-Vested UARs Number of Units Weighted- Average Exercise Price Non-vested at January 1, 2016 566,067 $ 16.80 Vested (221,387 ) 20.14 Forfeited (30,503 ) 19.80 Non-vested at December 31, 2016 314,177 $ 14.16 Legacy has used a weighted-average risk free interest rate of 1.6% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at December 31, 2016 . 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, 2016 2015 2014 Expected life (years) 4.02 4.91 5.15 Annual interest rate 1.6 % 1.7 % 1.6 % Annual distribution rate per unit $0.00 $0.60 $2.44 Volatility 87 % 59 % 38 % Phantom Units Legacy has also issued phantom units under the LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy accounts for the phantom units settled in Partnership units under the equity method. Legacy accounts for the phantom units settled in cash under the liability method. 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 five executive officers. During March 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. During June 2016 , the Compensation Committee approved with respect to Paul Horne, and the board of directors of LRGPLLC approved the recommendation of the Compensation Committee with respect to the other executive officers the award of a maximum of 391,674 subjective, or service-based, phantom units that, upon vesting, settle in Partnership units, a maximum of 1,286,930 subjective phantom units that, upon vesting, settle in cash and a maximum of 2,238,138 objective, or performance-based, phantom units that, upon vesting, settle in cash to Legacy's executive officers. Compensation expense related to the phantom units and associated DERs was $3.7 million , $3.4 million and $2.3 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Restricted Units During the year ended December 31, 2014 , Legacy issued an aggregate of 127,845 restricted units to non-executive employees . 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. During the year ended December 31, 2016 , Legacy issued an aggregate of 137,569 restricted units to non-executive employees. The restricted units vest ratably over a three -year period beginning at the date of grant. Compensation expense related to restricted units was $2.7 million , $2.7 million and $2.3 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. As of December 31, 2016 , there was a total of $2.4 million of unrecognized compensation costs related to the non-vested portion of these restricted units. At December 31, 2016 , this cost was expected to be recognized over a weighted-average period of 1.8 years. Pursuant to the provisions of ASC 718, Legacy’s issued units as reflected in the accompanying consolidated balance sheet at December 31, 2016 , do not include 484,447 units related to unvested restricted unit awards. Board Units On May 15, 2014 , Legacy granted and issued 3,628 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 $27.50 at the time of issuance. On June 15, 2015 , Legacy granted and issued 11,025 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 $9.13 at the time of issuance. On May 10, 2016 , Legacy granted and issued 39,526 units to each of its six non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $2.59 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, 2016
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors On October 17, 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.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, 2016 , Legacy recognized $61.8 million of impairment expense in 43 separate producing fields, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016 , which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2015 , Legacy recognized $633.8 million of impairment expense, $598.1 million 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. 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. Legacy did not recognize impairment expense on unproved properties during the year ended December 31, 2016. During the years ended December 31, 2015 and 2014 , Legacy recognized $35.7 million and $35.0 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 $(1.2) million , $1.5 million and $0.9 million for the years ended December 31, 2016 , 2015 and 2014 , 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 $1.3 billion at December 31, 2016 .
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. 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, 2016 , 2015 and 2014 .
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).
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, 2016 , do not include 484,447 units related to unvested restricted unit awards.
Restricted Cash	Restricted Cash Restricted cash of $3.6 million as of December 31, 2016 is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. There was no restricted cash recorded at December 31, 2015 .
Prior Year Financial Statement Presentation	Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K. Please read "—Footnote 3—Long-Term Debt" for further discussion regarding this reclassification.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our business and comparing historical accounting policies and practices to the new standard. Our contracts are primarily short-term in nature, and our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our financial statements upon adoption.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of components of accrued oil and natural gas liabilities	Below are the components of accrued oil and natural gas liabilities as of December 31, 2016 and 2015 . December 31, 2016 2015 (In thousands) Revenue payable to joint interest owners $ 19,576 $ 15,253 Accrued lease operating expense 17,696 19,007 Accrued capital expenditures 7,019 2,881 Accrued ad valorem tax 5,300 8,723 Other 3,657 4,709 $ 53,248 $ 50,573

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Instrument [Line Items]
Schedule of long-term debt	Long-term debt consists of the following at December 31, 2016 and 2015 : December 31, 2016 2015 (In thousands) Credit Facility due 2019 $ 463,000 $ 608,000 Second Lien Term Loans due 2020 60,000 — 8% Senior Notes due 2020 232,989 300,000 6.625% Senior Notes due 2021 432,656 550,000 1,188,645 1,458,000 Unamortized discount on Second Lien Term Loans and Senior Notes (12,802 ) (17,604 ) Unamortized debt issuance costs (a) (14,449 ) (12,782 ) Total long term debt $ 1,161,394 $ 1,427,614 ____________________ (a) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs are now recorded as a direct deduction from the carrying amount of debt. As such, debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or retained earnings.
8% Senior Notes due 2020
Debt Instrument [Line Items]
Schedule of debt redemption	Legacy has 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, 2016
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 (In thousands) Revenues $ 380,619 $ 687,829 Net loss attributable to unitholders $ (713,364 ) $ (243,197 ) Loss per unit — basic and diluted $ (10.35 ) $ (4.05 ) Units used in computing loss per unit: Basic 68,928 60,053 Diluted 68,928 60,053 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, 2016 2015 2014 WPX Acquisition (In thousands) Revenues $ 62,522 $ 69,504 $ 48,470 Excess of revenues over direct operating expenses $ 23,622 $ 22,324 $ 22,333 Anadarko Acquisitions Revenues $ 51,177 $ 22,881 $ — Excess of revenues over direct operating expenses $ 23,319 $ 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 $ 461,306 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 433,955

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis	The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 : 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) $ — $ (224 ) $ — $ (224 ) Oil and natural gas derivatives — 12,690 8 12,698 Interest rate swaps — 183 — 183 Total as of December 31, 2016 $ — $ 12,649 $ 8 $ 12,657 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 ____________________ (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, 2016 2015 2014 (In thousands) Beginning balance $ (4,493 ) $ 555 $ 20,615 Total gains (losses) 253 (10,029 ) (6,185 ) Settlements 4,248 4,981 677 Transfers — — (14,552 ) (a) Ending balance $ 8 $ (4,493 ) $ 555 Gains included in earnings relating to derivatives still held as of December 31, 2016, 2015 and 2014 $ 68 $ (4,493 ) $ 555 (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 were transferred to Level 2 instruments.
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, 2016 and 2015 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) 2016 Impairment(a) $ — $ — $ 60,729 Acquisitions(b) $ — $ — $ 11,998 2015 Impairment(a) $ — $ — $ 385,506 Acquisitions(b) $ — $ — $ 540,347 ____________________ (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, 2016 , Legacy incurred impairment charges of $61.8 million as oil and natural gas properties with a net cost basis of $122.5 million were written down to their fair value of $60.7 million . 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 . 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 was related to unproved properties acquired since 2010 that were no longer viable. (b) Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2016 , Legacy acquired oil and natural gas properties with a fair value of $12.0 million in 3 immaterial transactions, both individually and in the aggregate. 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 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 Instrume27

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of reconciliation of the changes in fair value of Legacy's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2016 , 2015 , and 2014 . December 31, 2016 2015 2014 (In thousands) Beginning fair value of commodity derivatives $ 118,427 $ 153,099 $ 17,673 Total gain (loss) crude oil derivatives (9,410 ) 25,715 101,813 Total gain (loss) natural gas derivatives (31,814 ) 72,538 36,279 Crude oil derivative cash settlements paid (received) (37,464 ) (91,953 ) 5,431 Natural gas derivative cash settlements received (27,041 ) (40,972 ) (8,097 ) Ending fair value of commodity derivatives $ 12,698 $ 118,427 $ 153,099
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, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 56,103 $ (30,648 ) $ 25,455 Interest rate derivatives 1,328 (68 ) 1,260 Total derivative assets $ 57,431 $ (30,716 ) $ 26,715 Offsetting Derivative Liabilities: Commodity derivatives $ (43,405 ) $ 30,648 $ (12,757 ) Interest rate derivatives (1,145 ) 68 (1,077 ) Total derivative liabilities $ (44,550 ) $ 30,716 $ (13,834 ) December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 )
Schedule of notional amounts of outstanding derivative positions	As of December 31, 2016 , 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 2017 182,500 $84.75 $84.75 2018 730,000 $55.04 $55.00 - $55.15 As of December 31, 2016 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2017 2,190,000 $(0.30) $(0.75) - $(0.05) As of December 31, 2016 , Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below: Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl 2017 2,190,000 $45.00 $59.02 2018 1,095,000 $45.83 $59.97 As of December 31, 2016 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl 2017 72,400 $60.00 $85.00 $104.20 As of December 31, 2016 , 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 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of December 31, 2016 , 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 Price Range Calendar Year Volumes (MMBtu) Price per MMBtu per MMBtu 2017 27,600,000 $3.36 $3.29 - $3.39 2018 42,200,000 $3.25 $3.04 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39 As of December 31, 2016 , Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below: Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu 2017 14,600,000 $2.90 $3.44 As of December 31, 2016 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Calendar Year Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu 2017 5,040,000 $3.75 $4.25 $5.53 As of December 31, 2016 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, SoCal 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: 2017 Average Volumes (MMBtu) Price per MMBtu NWPL 7,300,000 $(0.16) SoCal 2,500,250 $0.11 San Juan 2,500,250 $(0.10)
Schedule of total impact on interest expense from the mark-to-market and settlements	The total impact on interest expense from the mark-to-market and settlements was as follows: December 31, 2016 2015 2014 (In thousands) Beginning fair value of interest rate swaps $ (362 ) $ (2,080 ) $ (4,759 ) Total loss on interest rate swaps (2,108 ) (1,548 ) (551 ) Cash settlements paid 2,653 3,266 3,230 Ending fair value of interest rate swaps $ 183 $ (362 ) $ (2,080 )
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap assets and liabilities as of December 31, 2016 . Weighted Average Fixed Effective Maturity Estimated Fair Market Value at December 31, Notional Amount Rate Date Date 2016 (Dollars in thousands) $115,000 0.850 % 9/1/2015 9/1/2017 (11 ) $235,000 1.363 % 9/1/2015 9/1/2019 194 Total fair value of interest rate derivatives $ 183

Sales to Major Customers (Table

Sales to Major Customers (Tables)	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Schedule of revenue by major customer	For the year ended December 31, 2014 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below: 2016 2015 2014 Enterprise (Teppco) Crude Oil, LP 1% 6% 12% Plains Marketing, LP 6% 7% 10%

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 . December 31, 2016 2015 2014 (In thousands) Asset retirement obligation — beginning of period $ 286,405 $ 226,525 $ 175,786 Liabilities incurred with properties acquired 24 60,526 50,487 Liabilities incurred with properties drilled 1 92 941 Liabilities settled during the period (2,351 ) (2,615 ) (2,918 ) Liabilities associated with properties sold (24,605 ) (9,386 ) (5,891 ) Current period accretion 12,674 11,263 8,120 Asset retirement obligation — end of period $ 272,148 $ 286,405 $ 226,525

Partners' Equity (Tables)

Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Schedule of computation of basic and diluted income (loss) per unit	The following table sets forth the computation of basic and diluted loss per unit: Years Ended December 31, 2016 2015 2014 (In thousands) Net loss $ (55,820 ) $ (701,541 ) $ (283,645 ) Distributions to preferred unitholders (19,000 ) (19,000 ) (11,694 ) Net loss attributable to unitholders $ (74,820 ) $ (720,541 ) $ (295,339 ) Weighted average number of units outstanding 70,605 68,928 60,053 Effect of dilutive securities: Restricted and phantom units — — — Weighted average units and potential units outstanding 70,605 68,928 60,053 Basic and diluted loss per unit $ (1.06 ) $ (10.45 ) $ (4.92 )

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value 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 $ — Outstanding at January 1, 2016 936,116 $ 20.61 Expired (21,067 ) $ 16.07 Forfeited (30,503 ) $ 19.80 Outstanding at December 31, 2016 884,546 $ 20.75 3.68 $ — UARs exercisable at December 31, 2016 570,369 $ 24.38 2.77 $ —
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, 2016 : Non-Vested UARs Number of Units Weighted- Average Exercise Price Non-vested at January 1, 2016 566,067 $ 16.80 Vested (221,387 ) 20.14 Forfeited (30,503 ) 19.80 Non-vested at December 31, 2016 314,177 $ 14.16
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, 2016 2015 2014 Expected life (years) 4.02 4.91 5.15 Annual interest rate 1.6 % 1.7 % 1.6 % Annual distribution rate per unit $0.00 $0.60 $2.44 Volatility 87 % 59 % 38 %

Summary of Significant Accoun32

Summary of Significant Accounting Policies - Other Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)field	Dec. 31, 2015USD ($)field	Dec. 31, 2014USD ($)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 recorded of proved and unproved oil and natural gas properties		$ 598,100	$ 413,300
Number of impaired fields | field	43	218	250
Impairment expense	$ 61,796	$ 633,805	$ 448,714
Proved Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Impairment expense recorded of proved and unproved oil and natural gas properties	$ 61,800
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	$ 35,000

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Contingency [Line Items]
Income tax (expense) benefit	$ (1,229)	$ 1,498	$ 859
Partnership’s book basis in its net assets excess of Partnership’s net tax basis	$ 1,300,000
Texas | State jurisdiction
Income Tax Contingency [Line Items]
Franchise tax rate	1.00%

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Estimated economic useful life	15 years
Expected amortization expense, 2017	$ 396
Expected amortization expense, 2018	358
Expected amortization expense, 2019	349
Expected amortization expense, 2020	322
Expected amortization expense, 2021	$ 223

Summary of Significant Accoun35

Summary of Significant Accounting Policies - Unit-Based Compensation (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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)	484,447	550,447	254,183

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue payable to joint interest owners	$ 19,576	$ 15,253
Accrued lease operating expense	17,696	19,007
Accrued capital expenditures	7,019	2,881
Accrued ad valorem tax	5,300	8,723
Other	3,657	4,709
Accrued oil and natural gas liabilities	$ 53,248	$ 50,573

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted cash	$ 3,600,000	$ 0

Fair Values of Financial Inst38

Fair Values of Financial Instruments (Details) - Senior notes - USD ($) $ in Millions	Dec. 31, 2016	May 13, 2014	May 28, 2013	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	$ 179.4
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%	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	$ 302

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	May 13, 2014	May 28, 2013	Dec. 04, 2012
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,188,645,000	$ 1,458,000,000
Unamortized discount on Second Lien Term Loans and Senior Notes	(12,802,000)	(17,604,000)
Unamortized debt Issuance costs	(14,449,000)	(12,782,000)
Total long term debt	1,161,394,000	1,427,614,000
Second Lien Term Loans due 2020
Debt Instrument [Line Items]
Long-term debt, gross	60,000,000	0
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, gross	$ 232,989,000	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	$ 432,656,000	550,000,000	$ 300,000,000	$ 250,000,000
Stated interest rate	6.625%		6.625%	6.625%
Credit Facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 463,000,000	$ 608,000,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility (Details)	Apr. 01, 2014USD ($)	Mar. 10, 2011USD ($)	Dec. 31, 2016USD ($)	Feb. 21, 2017USD ($)	Oct. 25, 2016	Dec. 31, 2015USD ($)	May 13, 2014USD ($)	May 28, 2013USD ($)	Dec. 04, 2012USD ($)
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 1,188,645,000			$ 1,458,000,000
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	95.00%
Current borrowing capacity			$ 600,000,000
Purchase price of properties as a percentage of borrowing base required for potential re-determination of borrowing base, minimum	10.00%
Minimum percent of outstanding principal amount required for changes to credit agreement	66.67%
Ratio of indebtedness to EBITDA			4.5
Ratio of EBITDA to interest expense, minimum			2
Ratio of current assets to current liabilities, minimum			1
Minimum required cash and cash equivalents to secured debt ratio			1
Long-term debt, gross			$ 463,000,000			608,000,000
Interest rate at period end			3.91%
Remaining borrowing capacity			$ 135,100,000
Interest Paid			19,000,000
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 | ABR, one-month LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
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%
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]
Remaining borrowing capacity				$ 134,100,000
Second Lien Term Loan
Line of Credit Facility [Line Items]
Interest Paid			1,400,000
Senior notes
Line of Credit Facility [Line Items]
Interest Paid			47,900,000
$300 Million Term Loan at 12% | Second Lien Term Loan
Line of Credit Facility [Line Items]
Oil and gas properties required to be mortgaged					95.00%
8% Senior Notes due 2020 | Senior notes
Line of Credit Facility [Line Items]
Long-term debt, gross			232,989,000			300,000,000			$ 300,000,000
6.625% Senior Notes due 2021 | Senior notes
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 432,656,000			$ 550,000,000	$ 300,000,000	$ 250,000,000

Long-Term Debt - Second Lien Te

Long-Term Debt - Second Lien Term Loans (Details)	Oct. 25, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 01, 2020USD ($)	Dec. 31, 2018	Jun. 30, 2017
Debt Instrument [Line Items]
Repayments of long-term debt	$ 60,000,000	$ 376,402,000	$ 341,000,000	$ 1,275,000,000
Long-term debt, gross		1,188,645,000	$ 1,458,000,000
Second Lien Term Loan
Debt Instrument [Line Items]
Interest Paid		1,400,000
Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Aggregate principal amount	300,000,000
Aggregate additional borrowings available	$ 240,000,000
Upfront fee	2.00%
Stated interest rate	12.00%
Maximum payment of accrued interest allowed	50.00%
Maximum loan assignment	49.00%
Unused borrowing capacity fee	0.25%
Oil and gas production hedged, minimum	75.00%
Oil and gas properties required to be mortgaged	95.00%
Senior notes
Debt Instrument [Line Items]
Interest Paid		$ 47,900,000
Scenario, Forecast | Second Lien Term Loan | $300 Million Term Loan at 12%
Debt Instrument [Line Items]
Minimum required cash and cash equivalents to secured debt ratio							1
Ratio of secured debt to EBITDA						4.5
Scenario, Forecast | Senior notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 15,000,000

Long-Term Debt - Senior Notes (

Long-Term Debt - Senior Notes (Details) - USD ($)	Jun. 01, 2016	May 13, 2014	May 28, 2013	Dec. 04, 2012	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, gross					$ 1,188,645,000	$ 1,458,000,000
Senior notes
Debt Instrument [Line Items]
Interest Paid					47,900,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, gross				$ 300,000,000	$ 232,989,000	300,000,000
Stated interest rate				8.00%	8.00%
Debt instrument, issued, percent of par				97.848%
Face amount of repurchased debt					$ 52,000,000
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		$ 432,656,000	$ 550,000,000
Stated interest rate		6.625%	6.625%		6.625%
Debt instrument, issued, percent of par		99.00%	98.405%
Face amount of repurchased debt					$ 117,300,000
Face amount of converted debt	$ 15,000,000
Senior notes | 6.625% Senior Notes due 2021 | Change in Control
Debt Instrument [Line Items]
Redemption price percentage					101.00%
Senior notes | 6.625% Senior Notes due 2021 | 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%	100.00%
Limited Partner
Debt Instrument [Line Items]
Units issued in exchange for retirement of debt (in shares)					2,719,000
Limited Partner | Common Equity
Debt Instrument [Line Items]
Units issued in exchange for retirement of debt (in shares)	2,719,124

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 31, 2015	Jun. 04, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pro Forma Operating Results
Revenues				$ 380,619	$ 687,829
Net loss attributable to unitholders				$ (713,364)	$ (243,197)
Loss per unit — basic and diluted (in dollars per share)				$ (10.35)	$ (4.05)
Units Used In Computing Income (Loss) Per Unit [Abstract]
Basic (in shares)				68,928,000	60,053,000
Diluted (in shares)				68,928,000	60,053,000
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			$ 62,522	$ 69,504	$ 48,470
Excess of revenues over direct operating expenses			23,622	22,324	22,333
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	$ 461,306
Future abandonment costs	(27,351)
Fair value of net assets acquired	433,955
Units Used In Computing Income (Loss) Per Unit [Abstract]
Revenues			51,177	22,881	0
Excess of revenues over direct operating expenses			$ 23,319	$ 12,373	$ 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	$ 337,200
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, 2016	Dec. 31, 2015	Dec. 31, 2014
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		$ 111,299
Water Transfer Services | Blue Quail Energy Services, LLC | Board of Directors Chairman and Director
Related Party Transaction [Line Items]
Related party transaction amount		$ 98,297	$ 382,629	$ 84,470
Reimbursement | Moriah Powder River LLC | Board of Directors Chairman and Director
Related Party Transaction [Line Items]
Related party transaction amount	$ 500,000

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / bbl
Loss Contingencies [Line Items]
Purchase obligation, calculated floor price | $ / bbl	57.14
Estimated total future purchase obligation | $	$ 48.6
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 Concentra46

Business and Credit Concentrations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Bad debt expense	$ 0	$ 0	$ 0
Fair value of derivative transactions	$ 12,700,000

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)transaction	Dec. 31, 2015USD ($)transaction	Dec. 31, 2014USD ($)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	$ 1,181,909	$ 1,408,956
Impairment expense recorded of proved and unproved oil and natural gas properties		598,100	$ 413,300
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	61,800
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	35,000
Recurring
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	(224)	0
Fair value of assets (liabilities)	12,657	118,065
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	12,698	118,427
Recurring | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Derivative liability	183	(362)
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	(224)	0
Fair value of assets (liabilities)	12,649	122,558
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	12,690	122,920
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	183	(362)
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)	8	(4,493)
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance	(4,493)	555	20,615
Total gains (losses)	253	(10,029)	(6,185)
Settlements	4,248	4,981	677
Transfers	0	0	(14,552)
Ending balance	8	(4,493)	555
Gains included in earnings relating to derivatives still held as of December 31, 2016, 2015 and 2014	253	(10,029)	(6,185)
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)	68	(4,493)	555
Gains included in earnings relating to derivatives still held as of December 31, 2016, 2015 and 2014	68	(4,493)	$ 555
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	8	(4,493)
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]
Impairments	0	0
Acquisitions	0	0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	0	0
Acquisitions	0	0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairments	60,729	385,506
Acquisitions	11,998	540,347
Oil and gas properties, gross	$ 122,500	$ 983,600
Number of immaterial transactions | transaction	3	6

Derivative Financial Instrume48

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	$ (40,679)	$ 99,971	$ 140,771
Derivative cash settlements paid (received)	(64,505)	(132,925)	(2,666)
Ending fair value of derivatives	12,700
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	118,427	153,099	17,673
Ending fair value of derivatives	12,698	118,427	153,099
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(9,410)	25,715	101,813
Derivative cash settlements paid (received)	(37,464)	(91,953)	5,431
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(31,814)	72,538	36,279
Derivative cash settlements paid (received)	$ (27,041)	$ (40,972)	$ (8,097)

Derivative Financial Instrume49

Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Offsetting Derivative Assets [Abstract]
Gross Amounts of Recognized Assets	$ 57,431	$ 179,064
Gross Amounts Offset in the Consolidated Balance Sheets	(30,716)	(58,980)
Net Amounts Presented in the Consolidated Balance Sheets	26,715	120,084
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(44,550)	(60,999)
Gross Amounts Offset in the Consolidated Balance Sheets	30,716	58,980
Net Amounts Presented in the Consolidated Balance Sheets	(13,834)	(2,019)
Commodity derivatives
Offsetting Derivative Assets [Abstract]
Gross Amounts of Recognized Assets	56,103	177,082
Gross Amounts Offset in the Consolidated Balance Sheets	(30,648)	(58,655)
Net Amounts Presented in the Consolidated Balance Sheets	25,455	118,427
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(43,405)	(58,655)
Gross Amounts Offset in the Consolidated Balance Sheets	30,648	58,655
Net Amounts Presented in the Consolidated Balance Sheets	(12,757)	0
Interest rate derivatives
Offsetting Derivative Assets [Abstract]
Gross Amounts of Recognized Assets	1,328	1,982
Gross Amounts Offset in the Consolidated Balance Sheets	(68)	(325)
Net Amounts Presented in the Consolidated Balance Sheets	1,260	1,657
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(1,145)	(2,344)
Gross Amounts Offset in the Consolidated Balance Sheets	68	325
Net Amounts Presented in the Consolidated Balance Sheets	$ (1,077)	$ (2,019)

Derivative Financial Instrume50

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details)	Dec. 31, 2016USD ($)bblMMBTU$ / MMBTU$ / bbl
NYMEX WTI Swaps | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	182,500
Average Price per Bbl ($ per Bbl) | $ / bbl	84.75
NYMEX WTI Swaps | Crude Oil | 2017 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / bbl	84.75
NYMEX WTI Swaps | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	730,000
Average Price per Bbl ($ per Bbl) | $ / bbl	55.04
Price Range per Bbl ($ per Bbl) | $ / bbl	55
NYMEX WTI Swaps | Crude Oil | 2018 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / bbl	55.15
Midland-to-Cushing Differential Swaps | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	2,190,000
Average Price per Bbl ($ per Bbl) | $ / bbl	0.30
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / bbl	0.75
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl) | $ / bbl	0.05
NYMEX WTI Crude Oil Costless Collars | Crude Oil | 2017
Derivative [Line Items]
Volumes | MMBTU	2,190,000
Average Short Call Price for Crude Oil Collar	59.02
NYMEX WTI Crude Oil Costless Collars | Crude Oil | 2017 | Long
Derivative [Line Items]
Average Long Put Price for Crude Oil Collar	45
NYMEX WTI Crude Oil Costless Collars | Crude Oil | 2018
Derivative [Line Items]
Volumes | MMBTU	1,095,000
Average Short Call Price for Crude Oil Collar	59.97
NYMEX WTI Crude Oil Costless Collars | Crude Oil | 2018 | Long
Derivative [Line Items]
Average Long Put Price for Crude Oil Collar	45.83
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	72,400
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Long
Derivative [Line Items]
Average Strike Price | $ / bbl	85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	182,500
Average Price per Bbl ($ per Bbl) | $ / bbl	90.85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / bbl	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Long
Derivative [Line Items]
Average Strike Price | $ / bbl	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	127,750
Average Price per Bbl ($ per Bbl) | $ / bbl	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Short
Derivative [Line Items]
Average Strike Price | $ / bbl	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Long
Derivative [Line Items]
Average Strike Price | $ / bbl	57
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	27,600,000
Average Price per Bbl ($ per Bbl)	3.36
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2017 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.39
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018
Derivative [Line Items]
Volumes | MMBTU	42,200,000
Average Price per Bbl ($ per Bbl)	3.25
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.04
NYMEX Henry Hub and Waha Swaps | Natural gas | 2018 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.39
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019
Derivative [Line Items]
Volumes | MMBTU	25,800,000
Average Price per Bbl ($ per Bbl)	3.36
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.29
NYMEX Henry Hub and Waha Swaps | Natural gas | 2019 | Maximum
Derivative [Line Items]
Price Range per Bbl ($ per Bbl)	3.39
NYMEX Henry Hub, Waha Collar | Natural gas | 2018
Derivative [Line Items]
Volumes | MMBTU	14,600,000
Average Short Call Price for Natural Gas Collar	3.44
NYMEX Henry Hub, Waha Collar | Natural gas | 2018 | Long
Derivative [Line Items]
Average Long Put Price for Natural Gas Collar	2.90
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	5,040,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Long
Derivative [Line Items]
Average Strike Price	4.25
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	7,300,000
Average Price per Bbl ($ per Bbl)	0.16
Henry Hub NYMEX to California SoCal Natural Gas Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	2,500,250
Average Price per Bbl ($ per Bbl)	0.11
Henry Hub NYMEX to San Juan Basin Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	2,500,250
Average Price per Bbl ($ per Bbl)	0.10
Interest rate swaps
Derivative [Line Items]
Notional Amount, Liabilities | $	$ 115,000,000
Notional Amount, Assets | $	235,000,000
Estimated Fair Market Value, Liabilities | $	(11,000)
Estimated Fair Market Value, Assets | $	194,000
Estimated Fair Market Value, Net | $	$ 183,000
Interest rate swaps | Derivative assets
Derivative [Line Items]
Weighted Average Fixed	1.363%
Interest rate swaps | Derivative liabilities
Derivative [Line Items]
Weighted Average Fixed	0.85%
Put Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / bbl	60
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Short
Derivative [Line Items]
Average Strike Price	3.75
Call Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / bbl	104.20
Call Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Short
Derivative [Line Items]
Average Strike Price	5.53

Derivative Financial Instrume51

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Cash settlements paid	$ (64,505)	$ (132,925)	$ (2,666)
Ending fair value of derivatives	12,700
Interest rate swaps | Not designated as hedging instrument
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of derivatives	(362)	(2,080)	(4,759)
Cash settlements paid	2,653	3,266	3,230
Ending fair value of derivatives	183	(362)	(2,080)
Interest rate swaps | Not designated as hedging instrument | Interest expense
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total loss on interest rate swaps	$ (2,108)	$ (1,548)	$ (551)

Sales to Major Customers (Detai

Sales to Major Customers (Details) - Sales Revenue, Goods, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Enterprise (Teppco) Crude Oil, LP
Concentration Risk [Line Items]
Percentage of consolidated oil and natural gas revenue	1.00%	6.00%	12.00%
Plains Marketing, LP
Concentration Risk [Line Items]
Percentage of consolidated oil and natural gas revenue	6.00%	7.00%	10.00%

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in the ARO
Asset retirement obligation — beginning of period	$ 286,405	$ 226,525	$ 175,786
Liabilities incurred with properties acquired	24	60,526	50,487
Liabilities incurred with properties drilled	1	92	941
Liabilities settled during the period	(2,351)	(2,615)	(2,918)
Liabilities associated with properties sold	(24,605)	(9,386)	(5,891)
Current period accretion	12,674	11,263	8,120
Asset retirement obligation — end of period	$ 272,148	$ 286,405	$ 226,525

Asset Retirement Obligation Nar

Asset Retirement Obligation Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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, 2016	Dec. 31, 2014
Class of Stock [Line Items]
Liquidation preference (in dollars per share)							$ 25
Preferred dividends in arrears (in dollars per share)							$ 1.92
Preferred dividends in arrears							$ 18.2
WPX acquisition
Class of Stock [Line Items]
Consideration transferred (in shares)				300,000
Conversion terms, minimum distribution per share				$ 0.90
Required period from issue date after which award may be converted				3 years
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							5.256%
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Net loss	$ (55,820)	$ (701,541)	$ (283,645)
Distributions to preferred unitholders	(19,000)	(19,000)	(11,694)
Net loss attributable to unitholders	$ (74,820)	$ (720,541)	$ (295,339)
Weighted average number of units outstanding (in shares)	70,605,000	68,928,000	60,053,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	0
Weighted average unit and potential units outstanding (in shares)	70,605,000	68,928,000	60,053,000
Basic and diluted loss per unit (in dollars per share)	$ (1.06)	$ (10.45)	$ (4.92)
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)	484,447	550,447	254,183
Phantom share units (PSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)	1,212,692	862,064	323,965

Unit-Based Compensation - LTIP

Unit-Based Compensation - LTIP and Unit Appreciation Rights (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	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	$ 2,700,000	$ 2,300,000
Unrecognized compensation costs	$ 2,400,000
Unrecognized compensation costs, weighted-average remaining period for recognition	1 year 9 months 29 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 3,700,000	$ 3,400,000	$ 2,300,000
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
Unit award expiration period	7 years	7 years	7 years
Share-based compensation expense	$ 223,600	$ (10,700)	$ (1,260,000)
Unrecognized compensation costs	$ 129,093
Unrecognized compensation costs, weighted-average remaining period for recognition	1 year 7 months 1 day
Volatility	87.00%	59.00%	38.00%
Share based compensation, forfeiture rate	5.30%
Annual distribution rate per unit (in dollars per share)	$ 0	$ 0.60	$ 2.44
Annual interest rate	1.60%	1.70%	1.60%
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
Award vesting period		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
Award vesting period		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)	2,926,889
Long Term Incentive Plan | Unit option awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	266,014
Long Term Incentive Plan | Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	1,014,499
Long Term Incentive Plan | Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	1,212,692
Long Term Incentive Plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	433,684

Unit-Based Compensation - UAR A

Unit-Based Compensation - UAR Activity (Details) - Unit appreciation rights (UARs) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Units (in shares)
Outstanding (in shares)	936,116	671,229	627,043
Granted (in shares)		301,020	243,274
Exercised (in shares)			(137,252)
Expired (in shares)	21,067
Forfeited (in shares)	(30,503)	(36,133)	(61,836)
Outstanding (in shares)	884,546	936,116	671,229
Options and UARs exercisable (in shares)	570,369	372,049	220,056
Weighted-Average Exercise Price (in dollars per share)
Outstanding (in dollars per share)	$ 20.61	$ 26.97	$ 25.99
Granted (in dollars per share)		6.49	28.21
Exercised (in dollars per share)			24.35
Expired (in dollars per share)	16.07
Forfeited (in dollars per share)	19.80	21.07	27.27
Outstanding (in dollars per shares)	20.75	20.61	26.97
Options and UARs exercisable (in dollars per share)	$ 24.38	$ 26.45	$ 25.50
Weighted-Average Remaining Contractual Term
Outstanding	3 years 8 months 6 days	4 years 10 months 28 days	5 years 1 month 25 days
Options and UARs exercisable	2 years 9 months 6 days	3 years 3 months 10 days	3 years 6 months 5 days
Aggregate Intrinsic Value
Outstanding	$ 0	$ 0	$ 0
Options and UARs exercisable	$ 0	$ 0	$ 0

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, 2016$ / sharesshares
Number of Units (in shares)
Non-vested at January 1, 2016 | shares	566,067
Vested | shares	(221,387)
Forfeited | shares	(30,503)
Non-vested at December 31, 2016 | shares	314,177
Weighted- Average Exercise Price (in dollars per share)
Non-vested at January 1, 2016 | $ / shares	$ 16.80
Vested | $ / shares	20.14
Forfeited | $ / shares	19.80
Non-vested at December 31, 2016 | $ / shares	$ 14.16

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - Unit appreciation rights (UARs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	4 years 8 days	4 years 10 months 28 days	5 years 1 month 25 days
Annual interest rate	1.60%	1.70%	1.60%
Annual distribution rate per unit (in dollars per share)	$ 0	$ 0.60	$ 2.44
Volatility	87.00%	59.00%	38.00%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details) $ / shares in Units, $ in Millions	May 10, 2016director$ / sharesshares	Jun. 15, 2015director$ / sharesshares	May 15, 2014director$ / sharesshares	Jun. 30, 2016shares	Mar. 31, 2015shares	Mar. 31, 2014officershares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)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)							484,447	550,447	254,183
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	$ 2.59	$ 9.13
Subjective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				1,286,930	341,251	117,197
Objective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				2,238,138	259,998	102,572
Subjective or Service Based Phantom Units | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				391,674
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense | $							$ 3.7	$ 3.4	$ 2.3
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense | $							2.7	$ 2.7	$ 2.3
Unrecognized compensation costs | $							$ 2.4
Unrecognized compensation costs, period of recognition							1 year 9 months 29 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)									127,845
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)							137,569	381,860
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			$ 27.50
Unrestricted units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	39,526	11,025	3,628
Individuals eligible for plan | director	6	5	6

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details)	11 Months Ended
	May 08, 2014offering	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	May 13, 2014USD ($)	May 28, 2013USD ($)
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,188,645,000	$ 1,458,000,000
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Number of private offerings | offering	2
Long-term debt, gross		$ 432,656,000	$ 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%