Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Mar. 31, 2018	May 02, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Trading Symbol	BSM
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Common Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		105,220,326
Subordinated Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		96,328,836
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 6,297	$ 5,642
Accounts receivable	92,855	80,695
Commodity derivative assets	0	94
Prepaid expenses and other current assets	1,472	1,212
TOTAL CURRENT ASSETS	100,624	87,643
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,018,695 and $988,720 at March 31, 2018 and December 31, 2017, respectively	3,320,859	3,247,613
Accumulated depreciation, depletion, amortization, and impairment	(1,794,006)	(1,766,842)
Oil and natural gas properties, net	1,526,853	1,480,771
Other property and equipment, net of accumulated depreciation of $14,471 and $14,433 at March 31, 2018 and December 31, 2017, respectively	515	559
NET PROPERTY AND EQUIPMENT	1,527,368	1,481,330
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,986	7,478
TOTAL ASSETS	1,635,978	1,576,451
CURRENT LIABILITIES
Accounts payable	2,282	2,464
Accrued liabilities	35,292	52,631
Commodity derivative liabilities	17,290	4,222
Other current liabilities	350	417
TOTAL CURRENT LIABILITIES	55,214	59,734
LONG–TERM LIABILITIES
Credit facility	436,000	388,000
Accrued incentive compensation	4,079	3,648
Commodity derivative liabilities	947	1,263
Asset retirement obligations	14,382	14,092
Other long-term liabilities	38,876	19,171
TOTAL LIABILITIES	549,498	485,908
COMMITMENTS AND CONTINGENCIES (Note 8)
EQUITY
Partners' equity – general partner interest	0	0
Noncontrolling interests	842	867
TOTAL EQUITY	785,836	768,121
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,635,978	1,576,451
Series A Redeemable Preferred Units
MEZZANINE EQUITY
Partners' equity – Series A redeemable convertible preferred units, zero and 26 units outstanding at March 31, 2018 and December 31, 2017, respectively	0	27,028
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity – Series A redeemable convertible preferred units, zero and 26 units outstanding at March 31, 2018 and December 31, 2017, respectively	300,644	295,394
Common Units
EQUITY
Partners' equity - units	614,720	603,116
Subordinated Units
EQUITY
Partners' equity - units	$ 170,274	$ 164,138

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Oil and natural gas properties, unproved property costs	$ 1,018,695	$ 988,720
Other property and equipment accumulated depreciation and amortization	$ 14,471	$ 14,433
Series A Redeemable Preferred Units
Partners' equity, preferred units, outstanding (in shares)	0	26
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common Units
Partners' equity - units, outstanding (in shares)	104,926	103,456
Subordinated Units
Partners' equity - units, outstanding (in shares)	96,329	95,388

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUE
Oil and condensate sales	$ 72,983	$ 40,474
Natural gas and natural gas liquids sales	53,245	47,701
Lease bonus and other income	4,599	13,682
Revenue from contracts with customers	130,827	101,857
Gain (loss) on commodity derivative instruments	(16,333)	22,725
TOTAL REVENUE	114,494	124,582
OPERATING (INCOME) EXPENSE
Lease operating expense	4,248	4,189
Production costs and ad valorem taxes	14,925	11,902
Exploration expense	3	562
Depreciation, depletion, and amortization	28,570	26,379
General and administrative	18,521	17,212
Accretion of asset retirement obligations	269	247
(Gain) loss on sale of assets, net	(2)	(924)
TOTAL OPERATING EXPENSE	66,534	59,567
INCOME (LOSS) FROM OPERATIONS	47,960	65,015
OTHER INCOME (EXPENSE)
Interest and investment income	33	6
Interest expense	(4,521)	(3,507)
Other income (expense)	(1,515)	69
TOTAL OTHER EXPENSE	(6,003)	(3,432)
NET INCOME (LOSS)	41,957	61,583
Net (income) loss attributable to noncontrolling interests	(27)	(9)
Distributions on Series A redeemable preferred units	(25)	(1,114)
Distributions on Series B cumulative convertible preferred units	(5,250)	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	36,655	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	36,655	60,460
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 24,329	$ 35,517
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.23	$ 0.37
Weighted average units outstanding (basic) (in shares)	103,774	96,901
Per unit (diluted) (in dollars per share)	$ 0.23	$ 0.37
Weighted average units outstanding (diluted) (in shares)	103,838	97,590
DISTRIBUTIONS DECLARED AND PAID:
Per unit (in dollars per share)	$ 0.3125	$ 0.2875
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 12,326	$ 24,943
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.13	$ 0.26
Weighted average units outstanding (basic) (in shares)	95,395	95,149
Per unit (diluted) (in dollars per share)	$ 0.13	$ 0.26
Weighted average units outstanding (diluted) (in shares)	95,395	95,149
DISTRIBUTIONS DECLARED AND PAID:
Per unit (in dollars per share)	$ 0.20875	$ 0.1838

CONSOLIDATED STATEMENT OF EQUITY - 3 months ended Mar. 31, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Noncontrolling interests	Common Units	Subordinated Units	Partners' equity — common units	Partners' equity — subordinated units	Series B Preferred Stock	Series B Preferred Stock Partners' equity — common units
Beginning balance (in shares) at Dec. 31, 2017			103,456	95,388
Beginning balance at Dec. 31, 2017	$ 768,121	$ 867			$ 603,116	$ 164,138
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of Series A redeemable preferred units (in shares)			736	964
Conversion of Series A redeemable preferred units	24,248				10,498	13,750
Repurchases of common and subordinated units (in shares)			(451)	(23)
Repurchases of common and subordinated units	(8,441)				(8,099)	(342)
Issuance of common units, net of offering costs (in shares)			8
Issuance of common units, net of offering costs	138				138
Restricted units granted, net of forfeitures, units			1,177
Equity–based compensation	18,294				17,980	314
Distributions	(52,545)	(52)			(32,581)	(19,912)
Charges to partners' equity for accrued distribution equivalent rights	(661)				(661)
Distributions on preferred units	(25)				(13)	(12)	$ (5,250)	$ (5,250)
Net income (loss)	41,957	27			29,592	12,338
Ending balance (in shares) at Mar. 31, 2018			104,926	96,329
Ending balance at Mar. 31, 2018	$ 785,836	$ 842			$ 614,720	$ 170,274

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 41,957	$ 61,583
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	28,570	26,379
Accretion of asset retirement obligations	269	247
Amortization of deferred charges	205	215
(Gain) loss on commodity derivative instruments	16,333	(22,725)
Net cash (paid) received on settlement of commodity derivative instruments	(4,375)	4,278
Equity-based compensation	6,226	4,661
(Gain) loss on sale of assets, net	(2)	(924)
Changes in operating assets and liabilities:
Accounts receivable	(11,851)	(6,568)
Prepaid expenses and other current assets	(260)	(85)
Accounts payable, accrued liabilities, and other	(565)	(3,064)
Settlement of asset retirement obligations	(33)	(43)
NET CASH PROVIDED BY OPERATING ACTIVITIES	76,474	63,954
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(32,154)	(48,371)
Additions to oil and natural gas properties	(46,250)	(16,279)
Additions to oil and natural gas properties leasehold costs	(524)	(1,336)
Purchases of other property and equipment	(5)	(93)
Proceeds from the sale of oil and natural gas properties	752	1,993
Proceeds from farmouts of oil and natural gas properties	18,015	0
NET CASH USED IN INVESTING ACTIVITIES	(60,166)	(64,086)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units, net of offering costs	138	0
Distributions to noncontrolling interests	(52)	(25)
Redemptions of Series A redeemable preferred units	(2,115)	(12,742)
Borrowings under credit facility	105,000	103,000
Repayments under credit facility	(57,000)	(31,000)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(15,653)	4,365
NET CHANGE IN CASH AND CASH EQUIVALENTS	655	4,233
CASH AND CASH EQUIVALENTS – beginning of the period	5,642	9,772
CASH AND CASH EQUIVALENTS – end of the period	6,297	14,005
SUPPLEMENTAL DISCLOSURE
Interest paid	4,326	3,156
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(52,493)	(45,404)
Repurchases of common and subordinated units	(8,441)	(7,845)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (690)	$ (1,619)

Business and Basis of Presentation	3 Months Ended
Business and Basis of Presentation	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business and Basis of Presentation	BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its Credit Facility, as defined in Note 7 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.” Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States ("U.S."). In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 Series A redeemable preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries. In addition to mineral interests, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. These interests, which are non-cost-bearing, are collectively referred to as “mineral and royalty interests.” As of March 31, 2018, the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2017 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2018, with the exception of ASC 606, as defined below.

Accounts Receivable

The following table presents information about the Partnership's accounts receivable:



	March 31, 2018		December 31, 2017

	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	89,616	$	77,544
Other	3,239		3,151
Total accounts receivable	$	92,855	$	80,695

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) that supersedes Accounting Standards Codification ("ASC") 605, Revenue Recognition. Under the new standard, entities are required 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, which may require more judgment than under previous U.S. GAAP. See Note 3 – Impact of ASC 606 Adoption for further details related to the Partnership’s adoption of this standard.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. In January 2018, the FASB issued an amendment to this guidance in ASU 2018-01, Leases (Topic 842), "Land Easement Practical Expedient for Transition to Topic 842," which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.

The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach with respect to ASU 2016-02 and does not plan to early adopt. Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.

Impact of ASC 606 Adoption	3 Months Ended
Impact of ASC 606 Adoption	Mar. 31, 2018
Revenue Recognition and Deferred Revenue [Abstract]
Impact of ASC 606 Adoption	IMPACT OF ASC 606 ADOPTION ASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of January 1, 2018. Revenues from Contracts with Customers Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606-10-32-18. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Production imbalances The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. As such, upon adoption of ASC 606, there was no material impact to the financial statements due to this change in accounting for our production imbalances. Allocation of transaction price to remaining performance obligations Oil and natural gas sales The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not typically record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was immaterial.

Oil and Natural Gas Properties Acquisitions

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Oil and Natural Gas Properties Acquisitions

OIL AND NATURAL GAS PROPERTIES ACQUISITIONS

Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.

2018 Acquisitions

During the three months ended March 31, 2018, the Partnership closed on an acquisition of mineral and royalty interests, which also included producing properties, in the Permian Basin. The following table summarizes the acquisition:



	Assets Acquired								Cash Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid

	(in thousands)
March 2018	$	984	$	21,452	$	133	$	22,569	$	22,569

In addition, the Partnership acquired mineral and royalty interests from various sellers in the East Texas Basin for $9.6 million in cash. All 2018 acquisitions were funded via borrowings under the Partnership's Credit Facility as well as funds from operating activities.

Noble Acquisition

On November 28, 2017, BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition."

The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross (140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota.

The Partnership funded the $335.0 million purchase price (before customary post-closing adjustments) using (i) approximately $300.0 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group (the "Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35.0 million from borrowings under its Credit Facility. See additional discussion of the Series B cumulative convertible preferred units in Note 10 – Preferred Units.

The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date.

The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs.



	Assets Acquired								Cash Consideration Paid		Acquisition-Related Costs¹
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid		Acquisition-Related Costs¹

	(in thousands)
Noble Assets	$	68,877	$	259,749	$	5,917	$	334,543	$	334,543	$	247


¹	Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. 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.

Actual and Pro Forma Impact of Noble Acquisition (Unaudited)

Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the three months ended March 31, 2018 was $10.0 million. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017.



	Three Months Ended March 31, 2017
	(in thousands, except per unit amounts)
Revenue and other income	$	134,193
Net income	67,045
Net income attributable to noncontrolling interests	(9		)
Distributions on Series A redeemable preferred units	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)
Net income attributable to the general partner and common and subordinated units	$	60,672
Allocation of net income:
General partner interest	$	—
Common units	35,624
Subordinated units	25,048
	$	60,672
Net income attributable to limited partners per common and subordinated unit:
Per common unit (basic)	$	0.37
Per subordinated unit (basic)	$	0.26
Per common unit (diluted)	$	0.37
Per subordinated unit (diluted)	$	0.26

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments:


•	Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.


•	Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.


•	Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.


•	The Series B cumulative convertible preferred units were included in the calculation of pro forma diluted earnings per common unit for the period presented above due to their dilutive effect under the if-converted method; the Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.

2017 Acquisitions

In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests during the year ended December 31, 2017, which also included producing properties, as reflected in the table below. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility.



	Assets Acquired								Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash		Fair Value of Common Units Issued		Acquisition-Related Costs¹

	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	27,380	$	12,026	$	1,162
June	5,006		45,477		—		50,483		4,802		45,681		$	1,481
August	3,277		9,984		—		13,261		4,289		8,972		107
September	3,120		—		—		3,120		3,120		—		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	39,591	$	66,679	$	2,750


¹	Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

Additionally, the Partnership acquired mineral and royalty interests totaling $56.7 million from various sellers in East Texas during the year ended December 31, 2017. The cash portion of these acquisitions of $51.7 million was funded via borrowings under the Partnership's Credit Facility, with an additional $5.0 million funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

Farmout Agreements

On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of March 31, 2018, 16 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. Since the inception of the agreement, the Partnership has received $24.8 million from Canaan under the agreement. All amounts received are included in the Long-term liabilities – other long-term liabilities line item of the March 31, 2018 and December 31, 2017 consolidated balance sheets, as none of the drilled wells had been completed nor had any working interest been assigned to Canaan as of the balance sheet dates herein.

On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining approximate 20% working interest (10% working interest on an 8/8th basis) not covered by the Canaan Farmout, as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by its other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding the Partnership's working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells. Since the inception of the agreement, the Partnership has received $12.4 million from Pivotal under the agreement. All amounts received are included in the Long-term liabilities – other long-term liabilities line item of the March 31, 2018 and December 31, 2017 consolidated balance sheets, as none of the drilled wells had been completed nor had any working interest been assigned to Pivotal as of the balance sheet dates herein.

Commodity Derivative Financial Instruments

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivatives And Financial Instruments

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas derivative instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.

As of March 31, 2018, the Partnership’s open derivative contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, any changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of March 31, 2018 and December 31, 2017. See Note 6 – Fair Value Measurements for further discussion.

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2018, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Eight of the Partnership's counterparties are lenders under the Credit Facility. The Partnership would have been at risk of losing a fair value amount of $9.5 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of March 31, 2018.

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date:



		March 31, 2018
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	6,300	$	(6,300	)	$	—
Long-term asset	Deferred charges and other long-term assets	3,167		(1,916		)	1,251
Total assets		$	9,467	$	(8,216	)	$	1,251
Liabilities:
Current liability	Commodity derivative liabilities	$	23,590	$	(6,300	)	$	17,290
Long-term liability	Commodity derivative liabilities	2,863		(1,916		)	947
Total liabilities		$	26,453	$	(8,216	)	$	18,237



		December 31, 2017
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	10,713	$	(10,619	)	$	94
Long-term asset	Deferred charges and other long-term assets	1,392		(1,029		)	363
Total assets		$	12,105	$	(11,648	)	$	457
Liabilities:
Current liability	Commodity derivative liabilities	$	14,841	$	(10,619	)	$	4,222
Long-term liability	Commodity derivative liabilities	2,292		(1,029		)	1,263
Total liabilities		$	17,133	$	(11,648	)	$	5,485

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and are as follows:



	Three Months Ended March 31,
Derivatives not designated as hedging instruments	2018			2017

	(in thousands)
Beginning fair value of commodity derivative instruments	$	(5,028	)	$	(16,719	)
Gain (loss) on oil derivative instruments	(14,476		)	14,305
Gain (loss) on natural gas derivative instruments	(1,857		)	8,420
Net cash paid (received) on settlements of oil derivative instruments	5,148			(2,809		)
Net cash received on settlements of natural gas derivative instruments	(773		)	(1,469		)
Net change in fair value of commodity derivative instruments	(11,958		)	18,447
Ending fair value of commodity derivative instruments	$	(16,986	)	$	1,728

The Partnership had the following open derivative contracts for oil as of March 31, 2018:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2018
First Quarter	285,000	$	55.18	$	52.09	$	61.88
Second Quarter	841,000	55.27		52.09		61.88
Third Quarter	849,000	55.28		51.85		61.88
Fourth Quarter	854,000	55.18		51.85		61.88
2019
First Quarter	495,000	$	56.57	$	52.82	$	58.69
Second Quarter	495,000	56.57		52.82		58.69
Third Quarter	495,000	56.57		52.82		58.69
Fourth Quarter	495,000	56.57		52.82		58.69

The Partnership had the following open derivative contracts for natural gas as of March 31, 2018:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
Second Quarter	13,660,000	$	3.02	$	2.86	$	3.23
Third Quarter	13,600,000	3.01		2.90		3.23
Fourth Quarter	13,630,000	3.01		2.90		3.23
2019
First Quarter	7,200,000	$	2.86	$	2.81	$	2.93
Second Quarter	7,240,000	2.86		2.81		2.93
Third Quarter	7,280,000	2.86		2.81		2.93
Fourth Quarter	7,280,000	2.86		2.81		2.93

Fair Value Measurements

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the three months ended March 31, 2018 or the year ended December 31, 2017.

The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of March 31, 2018 and December 31, 2017 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for further discussion.

The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis:



	Fair Value Measurements Using						Effect of Counterparty Netting			Total
	Level 1		Level 2		Level 3		Effect of Counterparty Netting			Total

	(in thousands)
As of March 31, 2018
Financial Assets
Commodity derivative instruments	$	—	$	9,467	$	—	$	(8,216	)	$	1,251
Financial Liabilities
Commodity derivative instruments	$	—	$	26,453	$	—	$	(8,216	)	$	18,237
As of December 31, 2017
Financial Assets
Commodity derivative instruments	$	—	$	12,105	$	—	$	(11,648	)	$	457
Financial Liabilities
Commodity derivative instruments	$	—	$	17,133	$	—	$	(11,648	)	$	5,485

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities measured at fair value on a nonrecurring basis include certain nonfinancial assets and liabilities, as may be acquired in a business combination, and measurements of oil and natural gas property values for assessment of impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Oil and Natural Gas Properties Acquisitions.

Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of March 31, 2018 or December 31, 2017.

There were no assets measured at fair value on a nonrecurring basis for the three months ended March 31, 2018 and 2017.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Credit Facility	3 Months Ended
Credit Facility	Mar. 31, 2018
Debt Disclosure [Abstract]
Credit Facility	CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has a maximum credit amount of $1.0 billion. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The borrowing base is redetermined semi-annually, usually in October and April. Effective April 25, 2017, the borrowing base redetermination increased the borrowing base from $500.0 million to $550.0 million. On November 1, 2017, the Partnership amended and restated the credit agreement to create a swingline facility that permits short-term borrowings on same-day notice, make other changes to the hedging and restrictive covenants, and extend the maturity for a term of five years, which terminates on November 1, 2022. Effective May 4, 2018, the borrowing base was increased to $600.0 million. Borrowings under the Credit Facility bear interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime Rate plus a margin between 1.00% and 2.00%, with the margin depending on the borrowing base utilization. The weighted-average interest rate of the Credit Facility was 4.71% and 4.06% as of March 31, 2018 and December 31, 2017, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s producing properties. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of March 31, 2018, the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was $436.0 million and $388.0 million at March 31, 2018 and December 31, 2017, respectively. The unused portion of the available borrowings under the Credit Facility was $114.0 million and $162.0 million at March 31, 2018 and December 31, 2017, respectively.

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been made. Put Option Related to Noble Acquisition By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Temin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of March 31, 2018, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded. Litigation From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of March 31, 2018 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

Incentive Compensation

3 Months Ended

Mar. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Incentive Compensation

INCENTIVE COMPENSATION

The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018		2017

	(in thousands)
Cash — long-term incentive plan	$	818	$	422
Equity-based compensation — restricted common and subordinated units	3,405		1,808
Equity-based compensation — restricted performance units	2,242		2,353
Board of Directors incentive plan	579		500
Total incentive compensation expense	$	7,044	$	5,083

Preferred Units	3 Months Ended
Preferred Units	Mar. 31, 2018
Equity [Abstract]
Redeemable Preferred Units	PREFERRED UNITS Series A Redeemable Preferred Units As of March 31, 2018, there were no Series A redeemable preferred units outstanding, while as of December 31, 2017 there were 26,363 Series A redeemable preferred units outstanding with a carrying value of $27.0 million. This carrying value included accrued distributions of $0.7 million. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption was outside the control of the Partnership. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears. The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO. For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield. For the year ended December 31, 2017, 6,624 Series A redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. For the three months ended March 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017. Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million. The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926. The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $300.6 million and $295.4 million, including accrued distributions of $5.3 million and $1.9 million, as of March 31, 2018 and December 31, 2017, respectively. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

Earnings Per Unit

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Unit

EARNINGS PER UNIT

The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.

Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Series B cumulative convertible preferred units could be converted into 15.1 million common units as of March 31, 2018.

At March 31, 2018, if the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive; therefore, they are not included in the calculation of diluted EPU for the three months ended March 31, 2018.

The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At March 31, 2018, there were 0.1 million units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU.

The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:



	Three Months Ended March 31,
	2018			2017

	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	41,957		$	61,583
Net (income) loss attributable to noncontrolling interests	(27		)	(9		)
Distributions on Series A redeemable preferred units	(25		)	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	36,655		$	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—
Common units	24,329			35,517
Subordinated units	12,326			24,943
	$	36,655		$	60,460
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.23		$	0.37
Weighted average common units outstanding (basic)	103,774			96,901
Per subordinated unit (basic)	$	0.13		$	0.26
Weighted average subordinated units outstanding (basic)	95,395			95,149
Per common unit (diluted)	$	0.23		$	0.37
Weighted average common units outstanding (diluted)	103,838			97,590
Per subordinated unit (diluted)	$	0.13		$	0.26
Weighted average subordinated units outstanding (diluted)	95,395			95,149

At-The-Market Offering Program	3 Months Ended
At-The-Market Offering Program	Mar. 31, 2018
Equity [Abstract]
At-The-Market Offering Program	AT-THE-MARKET OFFERING PROGRAM On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange. Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent. The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility. Common units sold pursuant to the Equity Distribution Agreement are offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the SEC on February 8, 2017. The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions. For the three months ended March 31, 2018, the Partnership sold 8,204 common units under the ATM Program for net proceeds of $0.1 million.

Subsequent Events	3 Months Ended
Subsequent Events	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Effective May 4, 2018, the borrowing base of the Credit Facility was increased to $600.0 million from $550.0 million, as discussed in Note 7 – Credit Facility. On May 7, 2018, the Board of Directors of the Partnership's general partner approved a distribution for the three months ended March 31, 2018 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on May 24, 2018 to unitholders of record at the close of business on May 17, 2018.

Summary of Significant Accounting Policies (Policies)	3 Months Ended
Summary of Significant Accounting Policies (Policies)	Mar. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2017 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting	Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) that supersedes Accounting Standards Codification ("ASC") 605, Revenue Recognition. Under the new standard, entities are required 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, which may require more judgment than under previous U.S. GAAP. See Note 3 – Impact of ASC 606 Adoption for further details related to the Partnership’s adoption of this standard. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. In January 2018, the FASB issued an amendment to this guidance in ASU 2018-01, Leases (Topic 842), "Land Easement Practical Expedient for Transition to Topic 842," which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach with respect to ASU 2016-02 and does not plan to early adopt. Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.
Earnings Per Unit	The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.

Summary of Significant Accounting Policies - (Tables)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Schedule of Accounts Receivable

The following table presents information about the Partnership's accounts receivable:



	March 31, 2018		December 31, 2017

	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	89,616	$	77,544
Other	3,239		3,151
Total accounts receivable	$	92,855	$	80,695

Oil and Natural Gas Properties Acquisitions (Tables)

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Schedule of Fair Values of the Properties Acquired

The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs.



	Assets Acquired								Cash Consideration Paid		Acquisition-Related Costs¹
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid		Acquisition-Related Costs¹

	(in thousands)
Noble Assets	$	68,877	$	259,749	$	5,917	$	334,543	$	334,543	$	247


¹

The following table summarizes the acquisition:



	Assets Acquired								Cash Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid

	(in thousands)
March 2018	$	984	$	21,452	$	133	$	22,569	$	22,569



	Assets Acquired								Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash		Fair Value of Common Units Issued		Acquisition-Related Costs¹

	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	27,380	$	12,026	$	1,162
June	5,006		45,477		—		50,483		4,802		45,681		$	1,481
August	3,277		9,984		—		13,261		4,289		8,972		107
September	3,120		—		—		3,120		3,120		—		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	39,591	$	66,679	$	2,750


¹	Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

Schedule of Pro Forma Information From Business Acquisition

The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017.



	Three Months Ended March 31, 2017
	(in thousands, except per unit amounts)
Revenue and other income	$	134,193
Net income	67,045
Net income attributable to noncontrolling interests	(9		)
Distributions on Series A redeemable preferred units	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)
Net income attributable to the general partner and common and subordinated units	$	60,672
Allocation of net income:
General partner interest	$	—
Common units	35,624
Subordinated units	25,048
	$	60,672
Net income attributable to limited partners per common and subordinated unit:
Per common unit (basic)	$	0.37
Per subordinated unit (basic)	$	0.26
Per common unit (diluted)	$	0.37
Per subordinated unit (diluted)	$	0.26

Commodity Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Derivative [Line Items]

Summary of Fair Value and Classification of Derivative Instruments

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date:



		March 31, 2018
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	6,300	$	(6,300	)	$	—
Long-term asset	Deferred charges and other long-term assets	3,167		(1,916		)	1,251
Total assets		$	9,467	$	(8,216	)	$	1,251
Liabilities:
Current liability	Commodity derivative liabilities	$	23,590	$	(6,300	)	$	17,290
Long-term liability	Commodity derivative liabilities	2,863		(1,916		)	947
Total liabilities		$	26,453	$	(8,216	)	$	18,237



		December 31, 2017
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	10,713	$	(10,619	)	$	94
Long-term asset	Deferred charges and other long-term assets	1,392		(1,029		)	363
Total assets		$	12,105	$	(11,648	)	$	457
Liabilities:
Current liability	Commodity derivative liabilities	$	14,841	$	(10,619	)	$	4,222
Long-term liability	Commodity derivative liabilities	2,292		(1,029		)	1,263
Total liabilities		$	17,133	$	(11,648	)	$	5,485

Changes in Fair Value of Company's Commodity Derivative Instruments



	Three Months Ended March 31,
Derivatives not designated as hedging instruments	2018			2017

	(in thousands)
Beginning fair value of commodity derivative instruments	$	(5,028	)	$	(16,719	)
Gain (loss) on oil derivative instruments	(14,476		)	14,305
Gain (loss) on natural gas derivative instruments	(1,857		)	8,420
Net cash paid (received) on settlements of oil derivative instruments	5,148			(2,809		)
Net cash received on settlements of natural gas derivative instruments	(773		)	(1,469		)
Net change in fair value of commodity derivative instruments	(11,958		)	18,447
Ending fair value of commodity derivative instruments	$	(16,986	)	$	1,728

Oil and Natural Gas

Derivative [Line Items]

Summary of Open Derivative Contracts

The Partnership had the following open derivative contracts for oil as of March 31, 2018:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2018
First Quarter	285,000	$	55.18	$	52.09	$	61.88
Second Quarter	841,000	55.27		52.09		61.88
Third Quarter	849,000	55.28		51.85		61.88
Fourth Quarter	854,000	55.18		51.85		61.88
2019
First Quarter	495,000	$	56.57	$	52.82	$	58.69
Second Quarter	495,000	56.57		52.82		58.69
Third Quarter	495,000	56.57		52.82		58.69
Fourth Quarter	495,000	56.57		52.82		58.69

The Partnership had the following open derivative contracts for natural gas as of March 31, 2018:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
Second Quarter	13,660,000	$	3.02	$	2.86	$	3.23
Third Quarter	13,600,000	3.01		2.90		3.23
Fourth Quarter	13,630,000	3.01		2.90		3.23
2019
First Quarter	7,200,000	$	2.86	$	2.81	$	2.93
Second Quarter	7,240,000	2.86		2.81		2.93
Third Quarter	7,280,000	2.86		2.81		2.93
Fourth Quarter	7,280,000	2.86		2.81		2.93

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis:



	Fair Value Measurements Using						Effect of Counterparty Netting			Total
	Level 1		Level 2		Level 3		Effect of Counterparty Netting			Total

	(in thousands)
As of March 31, 2018
Financial Assets
Commodity derivative instruments	$	—	$	9,467	$	—	$	(8,216	)	$	1,251
Financial Liabilities
Commodity derivative instruments	$	—	$	26,453	$	—	$	(8,216	)	$	18,237
As of December 31, 2017
Financial Assets
Commodity derivative instruments	$	—	$	12,105	$	—	$	(11,648	)	$	457
Financial Liabilities
Commodity derivative instruments	$	—	$	17,133	$	—	$	(11,648	)	$	5,485

Incentive Compensation (Tables)

3 Months Ended

Mar. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Incentive Compensation Expense



	Three Months Ended March 31,
	2018		2017

	(in thousands)
Cash — long-term incentive plan	$	818	$	422
Equity-based compensation — restricted common and subordinated units	3,405		1,808
Equity-based compensation — restricted performance units	2,242		2,353
Board of Directors incentive plan	579		500
Total incentive compensation expense	$	7,044	$	5,083

Earnings Per Unit (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Common and Subordinated Unit

The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:



	Three Months Ended March 31,
	2018			2017

	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	41,957		$	61,583
Net (income) loss attributable to noncontrolling interests	(27		)	(9		)
Distributions on Series A redeemable preferred units	(25		)	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	36,655		$	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—
Common units	24,329			35,517
Subordinated units	12,326			24,943
	$	36,655		$	60,460
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.23		$	0.37
Weighted average common units outstanding (basic)	103,774			96,901
Per subordinated unit (basic)	$	0.13		$	0.26
Weighted average subordinated units outstanding (basic)	95,395			95,149
Per common unit (diluted)	$	0.23		$	0.37
Weighted average common units outstanding (diluted)	103,838			97,590
Per subordinated unit (diluted)	$	0.13		$	0.26
Weighted average subordinated units outstanding (diluted)	95,395			95,149

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions		3 Months Ended
	May 06, 2015 USD ($) $ / shares shares	Mar. 31, 2018 basin state shares
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage		20.00%
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located \| state		41
Number of onshore oil and natural gas producing basins \| basin		64
Common Units
Limited Partners Capital Account [Line Items]
Issuance of common units, net of offering costs (in shares)		8,000
Units exchanged in merger (in shares)	72,574,715
Capital units converted upon merger (in shares)		736,000
Common Units \| Predecessor
Limited Partners Capital Account [Line Items]
Units conversion ratio as part of merger	12.9465
Units conversion ratio split up as part of merger	0.4329
Common Units \| IPO \| Limited Partner
Limited Partners Capital Account [Line Items]
Issuance of common units, net of offering costs (in shares)	22,500,000
Price per common unit (in dollars per unit) \| $ / shares	$ 19
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions \| $	$ 391.5
Subordinated Units
Limited Partners Capital Account [Line Items]
Units exchanged in merger (in shares)	95,057,312
Capital units converted upon merger (in shares)		964,000
Subordinated Units \| Predecessor
Limited Partners Capital Account [Line Items]
Units conversion ratio split up as part of merger	0.5671
Preferred Units \| Predecessor
Limited Partners Capital Account [Line Items]
Capital units converted upon merger (in shares)	117,963

Summary of Significant Accounting Policies Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 92,855	$ 80,695
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	89,616	77,544
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 3,239	$ 3,151

Oil and Natural Gas Properties Acquisitions - Schedule of Fair Values of the Properties Acquired (Details) - USD ($) $ in Thousands		1 Months Ended			3 Months Ended		12 Months Ended
	Nov. 28, 2017	Sep. 30, 2017	Aug. 31, 2017	Jan. 31, 2017	Mar. 31, 2018	Jun. 30, 2017	Dec. 31, 2017	Mar. 31, 2017
Permian Basin
Business Acquisition [Line Items]
Proved oil and natural gas properties					$ 984
Unproved oil and natural gas properties					21,452
Net working capital					133
Total fair value					22,569
Cash Consideration Paid					$ 22,569
East Texas
Business Acquisition [Line Items]
Total fair value							$ 56,700
Noble Acquisition
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 68,877
Unproved oil and natural gas properties	259,749
Net working capital	5,917
Total fair value	334,543
Cash Consideration Paid	334,543
Acquisition-Related Costs	$ 247
2017 Acquisitions
Business Acquisition [Line Items]
Proved oil and natural gas properties		$ 3,120	$ 3,277	$ 5,135		$ 5,006	16,538
Unproved oil and natural gas properties		0	9,984	34,008		45,477	89,469
Net working capital		0	0	263		0	263
Total fair value		3,120	13,261	39,406		50,483	106,270
Cash Consideration Paid		3,120	4,289			4,802	39,591	$ 27,380
Acquisition-Related Costs		0	107	1,162		1,481	2,750
Fair Value of Common Units Issued		$ 0	$ 8,972	$ 12,026		$ 45,681	$ 66,679

Oil and Natural Gas Properties Acquisitions - Additional Information (Details) $ in Thousands				3 Months Ended	12 Months Ended
	Nov. 28, 2017 USD ($) a state shares	Nov. 21, 2017 well	Feb. 21, 2017 well phase	Mar. 31, 2018 USD ($) well	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Issuance of common units, net of offering costs				$ 138
Permian Basin
Business Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties				22,569
East Texas
Business Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties					$ 56,700
Payments to acquire oil, mineral, and royalty interests				$ 9,600	$ 51,700
Angelina County, Texas \| Farmout Agreement
Business Acquisition [Line Items]
Ownership interest, acreage, percent			50.00%
Number of wells anticipated to be drilled \| well			18
Exploratory Wells Drilled, Net Productive \| well				16
Additional wells to be drilled \| well			20
Number of phases			3
Angelina County, Texas \| Farmout Agreement \| Canaan Resource Partners
Business Acquisition [Line Items]
Business combination, pro forma information, revenue of acquiree since acquisition date, actual				$ 24,800
Number of additional phases \| phase			2
Term of phase (years)			2 years
Funding requirements, drilling and completion costs, percent			80.00%
Ownership interest in wells, percent			80.00%
Ownership interest, gross, percent			40.00%
Third phase, ownership interest in additional wells, percent			40.00%
Third phase, ownership interest in additional wells, gross, percent			20.00%
Third phase, funding requirements, drilling and completion costs, percent			40.00%
San Augustine County, Texas \| Farmout Agreement \| Pivotal
Business Acquisition [Line Items]
Business combination, pro forma information, revenue of acquiree since acquisition date, actual				12,400
Number of wells anticipated to be drilled \| well		80
Term of phase (years)		8 years
Ownership interest in wells, percent		20.00%
Ownership interest, gross, percent		10.00%
Asset acquisition, ownership interest, in wells operated by others, percent		100.00%
San Augustine County, Texas \| Farmout Agreement \| Minimum \| Pivotal
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		12.50%
San Augustine County, Texas \| Farmout Agreement \| Maximum \| Pivotal
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent		25.00%
Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Proceeds from issuance of convertible preferred stock	$ 300,000
Partners' equity — common units
Business Acquisition [Line Items]
Issuance of common units, net of offering costs				138
Partners' equity — common units \| East Texas
Business Acquisition [Line Items]
Issuance of common units, net of offering costs				5,000
Noble Acquisition
Business Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties	$ 334,543
Number of states major onshore oil and natural gas basins located \| state	20
Payments to acquire businesses, gross	$ 335,000
Business combination, pro forma information, revenue of acquiree since acquisition date, actual				$ 10,000
Noble Acquisition \| Series B Cumulative Convertible Preferred Units
Business Acquisition [Line Items]
Proceeds from issuance of convertible preferred stock	$ 300,000
Number of shares issued (in shares) \| shares	14,711,219
Revolving Credit Facility \| Senior Line of Credit \| Noble Acquisition
Business Acquisition [Line Items]
Long-term line of credit	$ 35,000
Mining Properties and Mineral Rights \| Noble Acquisition
Business Acquisition [Line Items]
Gas and oil area, developed, gross \| a	1,100,000
Gas and oil area, developed, net \| a	140,000
Non-participating Royalty Interest \| Noble Acquisition
Business Acquisition [Line Items]
Gas and oil area, developed, gross \| a	380,000
Overriding Royalty Interest \| Noble Acquisition
Business Acquisition [Line Items]
Gas and oil area, developed, gross \| a	600,000

Oil and Natural Gas Properties Acquisitions - Pro Forma Information (Details) - Noble Acquisition $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($) $ / shares
Business Acquisition [Line Items]
Revenue and other income	$ 134,193
Net income	67,045
Net income attributable to noncontrolling interests	(9)
Distributions on Series A redeemable preferred units	(1,114)
Distributions on Series B cumulative convertible preferred units	(5,250)
Net income attributable to the general partner and common and subordinated units	60,672
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income	$ 35,624
DISTRIBUTIONS DECLARED AND PAID:
Per unit (basic) (in usd per share) \| $ / shares	$ 0.37
Per unit (diluted) (in usd per share) \| $ / shares	$ 0.37
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income	$ 25,048
DISTRIBUTIONS DECLARED AND PAID:
Per unit (basic) (in usd per share) \| $ / shares	$ 0.26
Per unit (diluted) (in usd per share) \| $ / shares	$ 0.26

Commodity Derivative Financial Instruments - Additional Information (Details) $ in Thousands	Mar. 31, 2018 USD ($) counterparty	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Number of counterparties	9
Gross Fair Value, Assets \| $	$ 9,467	$ 12,105
Senior Line of Credit
Derivative [Line Items]
Number of counterparties	8

Commodity Derivative Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	$ 9,467	$ 12,105
Effect of Counterparty Netting, Assets	(8,216)	(11,648)
Net Carrying Value on Balance Sheet, Assets	1,251	457
Gross Fair Value, Liabilities	26,453	17,133
Effect of Counterparty Netting, Liabilities	(8,216)	(11,648)
Net Carrying Value on Balance Sheet, Liabilities	18,237	5,485
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	6,300	10,713
Effect of Counterparty Netting, Assets	(6,300)	(10,619)
Net Carrying Value on Balance Sheet, Assets	0	94
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	3,167	1,392
Effect of Counterparty Netting, Assets	(1,916)	(1,029)
Net Carrying Value on Balance Sheet, Assets	1,251	363
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	23,590	14,841
Effect of Counterparty Netting, Liabilities	(6,300)	(10,619)
Net Carrying Value on Balance Sheet, Liabilities	17,290	4,222
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	2,863	2,292
Effect of Counterparty Netting, Liabilities	(1,916)	(1,029)
Net Carrying Value on Balance Sheet, Liabilities	$ 947	$ 1,263

Commodity Derivative Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (16,333)	$ 22,725
Net cash received on settlements of derivative instruments	4,375	(4,278)
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	(5,028)	(16,719)
Net change in fair value of commodity derivative instruments	(11,958)	18,447
Ending fair value of commodity derivative instruments	(16,986)	1,728
Not Designated as Hedging Instrument \| Oil
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(14,476)	14,305
Net cash received on settlements of derivative instruments	5,148	(2,809)
Not Designated as Hedging Instrument \| Natural Gas
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(1,857)	8,420
Net cash received on settlements of derivative instruments	$ (773)	$ (1,469)

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	$ 9,467	$ 12,105
Effect of Counterparty Netting, Assets	(8,216)	(11,648)
Net Carrying Value on Balance Sheet, Assets	1,251	457
Gross Fair Value, Liabilities	26,453	17,133
Effect of Counterparty Netting, Liabilities	(8,216)	(11,648)
Net Carrying Value on Balance Sheet, Liabilities	18,237	5,485
Commodity Derivative Instruments \| Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of Counterparty Netting, Assets		(11,648)
Net Carrying Value on Balance Sheet, Assets	1,251	457
Effect of Counterparty Netting, Liabilities		(11,648)
Net Carrying Value on Balance Sheet, Liabilities	18,237	5,485
Commodity Derivative Instruments \| Fair Value Measurements, Recurring Basis \| Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	0	0
Gross Fair Value, Liabilities	0	0
Commodity Derivative Instruments \| Fair Value Measurements, Recurring Basis \| Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	9,467	12,105
Gross Fair Value, Liabilities	26,453	17,133
Commodity Derivative Instruments \| Fair Value Measurements, Recurring Basis \| Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets	0	0
Gross Fair Value, Liabilities	$ 0	$ 0

Credit Facility - Additional Information (Details)		3 Months Ended
Credit Facility - Additional Information (Details)	Nov. 01, 2017	Mar. 31, 2018 USD ($)	May 04, 2018 USD ($)	Dec. 31, 2017 USD ($)	Apr. 25, 2017 USD ($)	Oct. 31, 2016 USD ($)
Line Of Credit Facility [Line Items]
Credit facility		$ 436,000,000		$ 388,000,000
Senior Line of Credit \| Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity		$ 1,000,000,000
Borrowing base					$ 550,000,000.0	$ 500,000,000
Interest payable, term	5 years	90 days
Weighted average interest rate (percent)		4.71%		4.06%
Borrowing base threshold (percent)		50.00%
Credit facility		$ 436,000,000		$ 388,000,000
Unused portion of current borrowing base		$ 114,000,000		$ 162,000,000
Senior Line of Credit \| Revolving Credit Facility \| Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)		0.375%
Senior Line of Credit \| Revolving Credit Facility \| Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)		0.50%
Senior Line of Credit \| Revolving Credit Facility \| Minimum
Line Of Credit Facility [Line Items]
Interest payable, term		90 days
Current ratio		1
Senior Line of Credit \| Revolving Credit Facility \| Minimum \| LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.00%
Senior Line of Credit \| Revolving Credit Facility \| Minimum \| Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.00%
Senior Line of Credit \| Revolving Credit Facility \| Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX		3.5
Senior Line of Credit \| Revolving Credit Facility \| Maximum \| LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.00%
Senior Line of Credit \| Revolving Credit Facility \| Maximum \| Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.00%
Subsequent Event \| Senior Line of Credit \| Revolving Credit Facility
Line Of Credit Facility [Line Items]
Borrowing base			$ 600,000,000

Commitments and Contingencies - Additional Information (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017	Nov. 28, 2017
Business Acquisition [Line Items]
Provision for remediation costs	$ 0
Samedan
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired			100.00%
Comin
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired			100.00%
Noncontrolling interest, ownership percentage by noncontrolling owners		47.34%
Temin
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners		44.39%

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 818	$ 422
Total incentive compensation expense	7,044	5,083
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	3,405	1,808
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	2,242	2,353
Board of Directors \| Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 579	$ 500

Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands		3 Months Ended	12 Months Ended
	Nov. 28, 2017 USD ($) $ / shares shares	Mar. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) shares
Preferred Units
Class of Stock [Line Items]
Partners' equity, preferred units, outstanding (in shares) \| shares		0	26,363
Preferred units, outstanding value			$ 27,000
Accrued distributions			$ 700
Preferred units distribution rate		10.00%
Adjusted conversion price (in us dollars per share) \| $ / shares		$ 14.2683
Number of preferred units redeemed \| shares		2,115	19,704
Preferred stock, redemption amount		$ 2,100	$ 20,200
Number of preferred units converted (in shares) \| shares		24,248	6,624
Conversion of preferred units to common units		$ 24,200	$ 6,600
Common Units
Class of Stock [Line Items]
Adjusted conversion rate		30.3431
Conversion of preferred units (in shares) \| shares		735,758	200,996
Number of shares issued (in shares) \| shares		8,204
Subordinated Units
Class of Stock [Line Items]
Adjusted conversion rate		39.7427
Conversion of preferred units (in shares) \| shares		963,681	263,247
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Partners' equity, preferred units, outstanding (in shares) \| shares		14,711,000	14,711,000
Preferred units, outstanding value		$ 300,644	$ 295,394
Accrued distributions		5,300	$ 1,900
Preferred units distribution rate			7.00%
Shares, price per share (in dollars per share) \| $ / shares	$ 20.3926
Proceeds from issuance of convertible preferred stock	$ 300,000
Minimum underlying value for conversion trigger		$ 10,000
Series B Cumulative Convertible Preferred Units \| Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares) \| shares	14,711,219
Proceeds from issuance of convertible preferred stock	$ 300,000

Earnings Per Unit - Additional Information (Details) shares in Millions	3 Months Ended
	Mar. 31, 2018 shares
Common Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	15.1

Earnings Per Unit - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share Basic [Line Items]
Net income (loss)	$ 41,957	$ 61,583
Net (income) loss attributable to noncontrolling interests	(27)	(9)
Distributions on Series A redeemable preferred units	(25)	(1,114)
Distributions on Series B cumulative convertible preferred units	5,250	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	36,655	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	36,655	60,460
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 24,329	$ 35,517
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.23	$ 0.37
Weighted average units outstanding (basic) (in shares)	103,774	96,901
Per unit (diluted) (in dollars per share)	$ 0.23	$ 0.37
Weighted average units outstanding (diluted) (in shares)	103,838	97,590
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 12,326	$ 24,943
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.13	$ 0.26
Weighted average units outstanding (basic) (in shares)	95,395	95,149
Per unit (diluted) (in dollars per share)	$ 0.13	$ 0.26
Weighted average units outstanding (diluted) (in shares)	95,395	95,149

At-The-Market Offering Program (Details) - Common Units - USD ($)	3 Months Ended
	Mar. 31, 2018	May 26, 2017
Class of Stock [Line Items]
Equity Distribution Agreement, maximum value		$ 100,000,000
Number of common units sold, units	8,204
Proceeds from sale of common units	$ 100,000

Subsequent Events - Additional Information (Details) - USD ($)	May 07, 2018	May 04, 2018	Apr. 25, 2017	Oct. 31, 2016
Subsequent Event \| Common Units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in usd per unit)	$ 0.3125
Subsequent Event \| Subordinated Units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in usd per unit)	$ 0.20875
Revolving Credit Facility \| Senior Line of Credit
Subsequent Event [Line Items]
Borrowing base			$ 550,000,000.0	$ 500,000,000
Revolving Credit Facility \| Senior Line of Credit \| Subsequent Event
Subsequent Event [Line Items]
Borrowing base		$ 600,000,000

Commodity Derivative Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Swaps Contract - Not Designated as Hedging Instrument - Swap bbl in Thousands, MMBTU in Thousands	3 Months Ended
	Mar. 31, 2018 MMBTU $ / MMBTU $ / bbl bbl
First Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	285
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	55.18
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.09
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	61.88
Second Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	841
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	55.27
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.09
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	61.88
Second Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	13,660
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.02
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.86
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.23
Third Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	849
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	55.28
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	51.85
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	61.88
Third Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	13,600
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.01
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.90
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.23
Fourth Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	854
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	55.18
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	51.85
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	61.88
Fourth Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	13,630
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.01
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.90
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.23
First Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	495
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	56.57
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	58.69
First Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	7,200
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.86
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.81
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93
Second Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	495
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	56.57
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	58.69
Second Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	7,240
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.86
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.81
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93
Third Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	495
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	56.57
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	58.69
Third Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	7,280
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.86
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.81
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93
Fourth Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	495
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	56.57
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	58.69
Fourth Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	7,280
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.86
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.81
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93