Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2017	Nov. 01, 2017
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
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)		103,417,081
Subordinated Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		95,388,424
Preferred Units
Document Information [Line Items]
Entity Partnership Units Outstanding (in shares)		26,426

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 8,911	$ 9,772
Accounts receivable	68,895	68,181
Commodity derivative assets	4,724	0
Prepaid expenses and other current assets	1,269	1,036
TOTAL CURRENT ASSETS	83,799	78,989
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $731,978 and $605,736 at September 30, 2017 and December 31, 2016, respectively	2,892,447	2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,736,695)	(1,652,930)
Oil and natural gas properties, net	1,155,752	1,044,143
Other property and equipment, net of accumulated depreciation of $14,384 and $14,327 at September 30, 2017 and December 31, 2016, respectively	519	528
NET PROPERTY AND EQUIPMENT	1,156,271	1,044,671
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	6,000	5,167
TOTAL ASSETS	1,246,070	1,128,827
CURRENT LIABILITIES
Accounts payable	3,659	4,142
Accrued liabilities	38,336	50,952
Commodity derivative liabilities	0	16,237
Other current liabilities	302	0
TOTAL CURRENT LIABILITIES	42,297	71,331
LONG-TERM LIABILITIES
Credit facility	362,000	316,000
Accrued incentive compensation	2,883	1,485
Commodity derivative liabilities	0	482
Deferred revenue	0	518
Asset retirement obligations	13,909	13,350
Other long-term liability	6,592	0
TOTAL LIABILITIES	427,681	403,166
COMMITMENTS AND CONTINGENCIES (Note 8)
MEZZANINE EQUITY
Partners' equity - convertible redeemable preferred units, 26 and 53 units outstanding at September 30, 2017 and December 31, 2016, respectively	27,092	54,015
EQUITY
Partners' equity - general partner interest	0	0
Noncontrolling interests	904	1,021
TOTAL EQUITY	791,297	671,646
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	1,246,070	1,128,827
Common Units
EQUITY
Partners' equity - units	608,998	489,023
Subordinated Units
EQUITY
Partners' equity - units	$ 181,395	$ 181,602

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Oil and natural gas properties, unproved property costs	$ 731,978	$ 605,736
Other property and equipment accumulated depreciation and amortization	$ 14,384	$ 14,327
Preferred Units
Partners' equity, preferred units, outstanding (in shares)	26,426	52,691
Common Units
Partners' equity - units, outstanding (in shares)	103,324,000	95,721,000
Subordinated Units
Partners' equity - units, outstanding (in shares)	95,388,424	95,164,000

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUE
Oil and condensate sales	$ 41,361	$ 42,780	$ 119,097	$ 104,581
Natural gas and natural gas liquids sales	45,047	38,986	142,651	85,706
Gain (loss) on commodity derivative instruments	(9,341)	7,813	35,387	(12,295)
Lease bonus and other income	12,044	9,592	37,082	26,129
TOTAL REVENUE	89,111	99,171	334,217	204,121
OPERATING (INCOME) EXPENSE
Lease operating expense	4,569	5,007	12,906	14,179
Production costs and ad valorem taxes	11,549	9,228	35,314	23,301
Exploration expense	8	6	616	643
Depreciation, depletion, and amortization	29,204	28,731	84,483	79,654
Impairment of oil and natural gas properties	0	0	0	6,775
General and administrative	17,305	16,677	51,998	52,213
Accretion of asset retirement obligations	260	206	760	680
(Gain) loss on sale of assets, net	0	0	(931)	(4,772)
TOTAL OPERATING EXPENSE	62,895	59,855	185,146	172,673
INCOME (LOSS) FROM OPERATIONS	26,216	39,316	149,071	31,448
OTHER INCOME (EXPENSE)
Interest and investment income	(9)	460	30	651
Interest expense	(4,172)	(2,282)	(11,660)	(4,773)
Other income (expense)	(1)	41	352	148
TOTAL OTHER EXPENSE	(4,182)	(1,781)	(11,278)	(3,974)
NET INCOME (LOSS)	22,034	37,535	137,793	27,474
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	20	8	27	15
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(666)	(1,324)	(2,452)	(4,439)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	21,388	36,219	135,368	23,050
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	21,388	36,219	135,368	23,050
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 16,371	$ 23,114	$ 83,989	$ 24,343
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.16	$ 0.24	$ 0.86	$ 0.26
Weighted average units outstanding (basic) (in shares)	101,623	95,740	97,777	95,086
Per unit (diluted) (in dollars per share)	$ 0.16	$ 0.24	$ 0.86	$ 0.26
Weighted average units outstanding (diluted) (in shares)	101,623	96,011	97,777	95,619
DISTRIBUTIONS DECLARED AND PAID:
Per unit (in dollars per share)	$ 0.3125	$ 0.2875	$ 0.8875	$ 0.8125
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 5,017	$ 13,105	$ 51,379	$ (1,293)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.05	$ 0.14	$ 0.54	$ (0.01)
Weighted average units outstanding (basic) (in shares)	95,388	95,189	95,269	95,125
Per unit (diluted) (in dollars per share)	$ 0.05	$ 0.14	$ 0.54	$ (0.01)
Weighted average units outstanding (diluted) (in shares)	95,388	95,189	95,269	95,467
DISTRIBUTIONS DECLARED AND PAID:
Per unit (in dollars per share)	$ 0.20875	$ 0.1838	$ 0.57625	$ 0.5513

CONSOLIDATED STATEMENT OF EQUITY - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands	Total	Noncontrolling interests	Common Units	Subordinated Units	Partners' equity— common units	Partners' equity— subordinated units
Beginning balance (in shares) at Dec. 31, 2016			95,721,000	95,164,000
Beginning balance at Dec. 31, 2016	$ 671,646	$ 1,021			$ 489,023	$ 181,602
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted units granted, net of forfeitures (in shares)			1,576,000	0
Equity-based compensation	26,316				26,430	(114)
Conversion of redeemable preferred units (in shares)			201,000	263,000
Conversion of redeemable preferred units	6,624				2,868	3,756
Repurchases of common and subordinated units (in shares)			(427,000)	(39,000)
Repurchases of common and subordinated units	(7,845)				(7,553)	(292)
Issuance of units for property acquisitions (in shares)			4,341,000
Issuance of units for property acquisitions	71,592				71,592
Distributions	(142,665)	(90)			(87,651)	(54,924)
Charges to partners' equity for accrued distribution equivalent rights	(979)				(979)
Net income (loss)	137,793	(27)			85,243	52,577
Issuance of common units, net of offering costs (in shares)			1,912,000
Issuance of common units, net of offering costs	31,267				31,267
Distributions on redeemable preferred units	(2,452)				(1,242)	(1,210)
Ending balance (in shares) at Sep. 30, 2017			103,324,000	95,388,424
Ending balance at Sep. 30, 2017	$ 791,297	$ 904			$ 608,998	$ 181,395

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 137,793	$ 27,474
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	84,483	79,654
Impairment of oil and natural gas properties	0	6,775
Accretion of asset retirement obligations	760	680
Amortization of deferred charges	661	594
(Gain) loss on commodity derivative instruments	(35,387)	12,295
Net cash received on settlement of commodity derivative instruments	12,339	39,220
Equity-based compensation	18,614	33,120
(Gain) loss on sale of assets, net	(931)	(4,772)
Changes in operating assets and liabilities:
Accounts receivable	(709)	(23,144)
Prepaid expenses and other current assets	(234)	(862)
Accounts payable and accrued liabilities	(3,940)	(29,063)
Deferred revenue	(1,670)	(175)
Settlement of asset retirement obligations	(113)	(237)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	211,666	141,559
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(89,030)	(140,893)
Additions to oil and natural gas properties	(40,680)	(63,039)
Purchases of other property and equipment	(118)	(5)
Proceeds from farmout of oil and gas properties	6,592	0
Proceeds from the sale of oil and natural gas properties	6,754	177
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(116,482)	(203,760)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under senior line of credit	208,500	304,500
Repayments of borrowings under senior line of credit	(162,500)	(71,500)
Distributions to non-controlling interests	(90)	(83)
Proceeds from issuance of common units	31,267	0
Redemptions of redeemable preferred units	(19,641)	(18,461)
Loan origination fees	(50)	0
Repurchases of common and subordinated units	(7,845)	(24,696)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(96,045)	53,816
NET CHANGE IN CASH AND CASH EQUIVALENTS	(861)	(8,385)
CASH AND CASH EQUIVALENTS - beginning of the period	9,772	13,233
CASH AND CASH EQUIVALENTS - end of the period	8,911	4,848
SUPPLEMENTAL DISCLOSURE
Interest paid	11,041	4,060
Common and Subordinated Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(142,575)	(130,883)
Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (3,111)	$ (5,061)

Business and Basis of Presentation	9 Months Ended
Business and Basis of Presentation	Sep. 30, 2017
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. 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. 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 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 September 30, 2017, the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental United States, 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 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. 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. 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. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year. 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 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 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

9 Months Ended

Sep. 30, 2017

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, 2016. There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2017.

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 will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

The Partnership intends to use the modified retrospective adoption approach and does not plan to early adopt. The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard is not anticipated to have a material impact on the consolidated financial statements. The Partnership is concurrently evaluating the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership continues to evaluate the disclosure requirements of this new guidance, and expects to fully complete its evaluation of the impacts of ASU 2014-09 to the consolidated financial statements and related disclosures by 2017 year end.

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. 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 and does not plan to early adopt. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its 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.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is permitted. The Partnership intends to use the retrospective transition method, does not plan to early adopt, and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted under certain circumstances. The amendments in this ASU should be applied prospectively as of the beginning of the period of adoption. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.

In May 2017, the FASB issued ASU 2017-09 Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:


•	The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.


•	The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.


•	The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.

This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations (“ARO”) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of its properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of these obligations. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability during the period:



	For the nine months ended
	September 30, 2017
	(In thousands)
Beginning asset retirement obligations	$	13,350
Liabilities incurred	290
Liabilities settled	(113		)
Accretion expense	760
Dispositions	(5		)
Revisions	(71		)
Ending asset retirement obligations	$	14,211
Current asset retirement obligations	$	302
Non-current asset retirement obligations	$	13,909

Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Acquisitions and Dispositions

ACQUISITIONS AND DISPOSITIONS

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.

2017 Acquisitions

During the nine months ended September 30, 2017, the Partnership closed on multiple acquisitions of mineral and royalty interests in the Delaware Basin and East Texas, which also included producing properties.

The following table summarizes the asset acquisitions which included producing properties:



	Proved		Unproved		Net Working Capital		Total Fair Value		Acquisition-Related Costs¹		Cash		Fair Value of Common Units Issued
	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	1,162	$	27,380	$	12,026
June	5,006		45,477		—		50,483		1,468		4,802		45,681
August	3,277		9,984		—		13,261		89		4,289		8,972
September	3,120		—		—		3,120		—		3,120		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	2,719	$	39,591	$	66,679

¹ Acquisition-related costs were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.

In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as follows:



	Unproved		Cash		Fair Value of Common Units Issued
	(in thousands)
Q1 2017	$	21,189	$	21,017	$	172
Q2 2017	13,329		13,329		—
Q3 2017	19,946		15,205		4,741
	$	54,464	$	49,551	$	4,913

The cash portion of all acquisitions during the nine months ended September 30, 2017 was funded via borrowings under the Partnership's credit facility.

Canaan Farmout

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. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of two years or until an additional 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. The execution of this agreement is anticipated to offset the Partnership's future capital expenditures by approximately $30 to $35 million in 2017 and by an average of $40 to $50 million annually during the term of the agreement.

2016 Acquisitions

During the nine months ended September 30, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage across a diverse oil and natural gas mineral asset package, including an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair values assigned to the properties acquired:



	Proved		Unproved		Net Working Capital		ARO			Total Fair Value		Cash
	(in thousands)
June	$	39,735	$	79,827	$	2,064	$	(50	)	$	121,576	$	121,576

The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash, respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.0 million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's credit facility.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
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+ Details

Derivatives and Financial Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Financial Instruments

DERIVATIVES AND 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 fixed-price-swap contracts, costless collars, 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 September 30, 2017, 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 September 30, 2017 and December 31, 2016. See Note 6 – Fair Value Measurement 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 September 30, 2017, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of the Partnership's counterparties are lenders under the Partnership's credit facility. The Partnership would have been at risk of losing a fair value amount of $7.2 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of September 30, 2017.

The table below summarizes the fair value and classification of the Partnership’s derivative instruments:



As of September 30, 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	$	5,338	$	(614	)	$	4,724
Long-term asset	Deferred charges and other long-term assets	1,822		(217		)	1,605
Total assets		$	7,160	$	(831	)	$	6,329
Liabilities:
Current liability	Commodity derivative liabilities	$	614	$	(614	)	$	—
Long-term liability	Commodity derivative liabilities	217		(217		)	—
Total liabilities		$	831	$	(831	)	$	—



As of December 31, 2016
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	$	3,879	$	(3,879	)	$	—
Long-term asset	Deferred charges and other long-term assets	—		—			—
Total assets		$	3,879	$	(3,879	)	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	20,116	$	(3,879	)	$	16,237
Long-term liability	Commodity derivative liabilities	482		—			482
Total liabilities		$	20,598	$	(3,879	)	$	16,719

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. Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows:



	For the Nine Months Ended September 30,
Derivatives not designated as hedging instruments	2017			2016
	(In thousands)
Beginning fair value of commodity derivative instruments	$	(16,719	)	$	64,534
Gain (loss) on oil derivative instruments	18,306			(8,906		)
Gain (loss) on natural gas derivative instruments	17,081			(3,389		)
Net cash received on settlements of oil derivative instruments	(10,682		)	(23,034		)
Net cash received on settlements of natural gas derivative instruments	(1,657		)	(16,186		)
Net change in fair value of commodity derivative instruments	23,048			(51,515		)
Ending fair value of commodity derivative instruments	$	6,329		$	13,019

The Partnership had the following open derivative contracts for oil as of September 30, 2017:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2017
Third Quarter	172,000	$	53.31	$	52.40	$	55.23
Fourth Quarter	687,000	53.21		52.02		55.23
2018
First Quarter	611,000	$	54.18	$	52.09	$	55.05
Second Quarter	573,000	54.16		52.09		54.90
Third Quarter	541,000	54.16		51.85		54.90
Fourth Quarter	502,000	54.22		51.85		54.90

The Partnership had the following open derivative contracts for natural gas as of September 30, 2017:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2017
Fourth Quarter	13,130,000	$	3.13	$	2.92	$	3.57
2018
First Quarter	12,570,000	$	3.06	$	2.96	$	3.45
Second Quarter	11,340,000	3.03		2.86		3.23
Third Quarter	9,630,000	3.02		2.90		3.23
Fourth Quarter	8,210,000	3.01		2.90		3.23

Subsequent to September 30, 2017, the Partnership entered into the following oil derivative contracts:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2017
Fourth Quarter	30,000	$	56.51	$	55.87	$	57.15
2018
First Quarter	130,000	$	55.02	$	53.99	$	57.15
Second Quarter	175,000	54.73		53.99		56.75
Third Quarter	215,000	54.71		53.99		55.87
Fourth Quarter	255,000	54.22		52.82		55.87
2019
First Quarter	165,000	$	53.58	$	52.82	$	54.02
Second Quarter	165,000	53.58		52.82		54.02
Third Quarter	165,000	53.58		52.82		54.02
Fourth Quarter	165,000	53.58		52.82		54.02

Additionally, subsequent to September 30, 2017, the Partnership entered into the following natural gas derivative contracts:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
First Quarter	1,020,000	$	3.11	$	3.01	$	3.21
Second Quarter	2,320,000	3.00		2.93		3.04
Third Quarter	3,970,000	3.00		2.93		3.04
Fourth Quarter	5,420,000	3.00		2.92		3.04
2019
First Quarter	3,600,000	$	2.91	$	2.90	$	2.93
Second Quarter	3,600,000	2.91		2.90		2.93
Third Quarter	3,600,000	2.91		2.90		2.93
Fourth Quarter	3,600,000	2.91		2.90		2.93

Fair Value Measurement

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurement

FAIR VALUE MEASUREMENT

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 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 nine months ended September 30, 2017 or the year ended December 31, 2016.

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 September 30, 2017 and December 31, 2016 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 – Derivatives and 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
	Level 1		Level 2		Level 3		Effect of Counterparty Netting			Total
	(In thousands)
As of September 30, 2017
Financial Assets
Commodity derivative instruments	$	—	$	7,160	$	—	$	(831	)	$	6,329
Financial Liabilities
Commodity derivative instruments	$	—	$	831	$	—	$	(831	)	$	—
As of December 31, 2016
Financial Assets
Commodity derivative instruments	$	—	$	3,879	$	—	$	(3,879	)	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	20,598	$	—	$	(3,879	)	$	16,719

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 – Acquisitions and Dispositions.

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 economic reserves, future operating and development costs, future commodity prices, 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 September 30, 2017 or December 31, 2016.

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



	Fair Value Measurements Using¹							Net Book Value¹
	Level 1			Level 2		Level 3		Net Book Value¹		Impairment
	(In thousands)
Three months ended September 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Three months ended September 30, 2016
Impaired oil and natural gas properties	$	—		$	—	$	—	$	—	$	—
Nine months ended September 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Nine months ended September 30, 2016
Impaired oil and natural gas properties	$	—	—	$	—	$	3,042	$	9,817	$	6,775

¹Amounts represent value on the dates of assessment.

- 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	9 Months Ended
Credit Facility	Sep. 30, 2017
Debt Disclosure [Abstract]
Credit Facility	CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Senior Line of Credit”). The Senior Line of Credit 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. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes. Effective April 15, 2016, the borrowing base was $450.0 million. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million, which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million. On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swingline facility and make other changes to the hedging and restrictive covenants. There was no change to the borrowing base. The Senior Line of Credit now terminates on November 1, 2022. Prior to October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between 1.50% and 2.50%, or the Prime Rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage. The Prime Rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. Effective October 31, 2016, borrowings under the Senior Line of Credit bore 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 Senior Line of Credit was 3.74% and 3.26% as of September 30, 2017 and December 31, 2016, 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 Senior Line of Credit is secured by substantially all of the Partnership’s producing oil and natural gas assets. The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of Credit 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 September 30, 2017, the Partnership was in compliance with all financial covenants for the Senior Line of Credit. The aggregate principal balance outstanding was $362.0 million and $316.0 million at September 30, 2017 and December 31, 2016, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $188.0 million and $184.0 million at September 30, 2017 and December 31, 2016, respectively.

Commitments and Contingencies	9 Months Ended
Commitments and Contingencies	Sep. 30, 2017
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. 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 September 30, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

Incentive Compensation

9 Months Ended

Sep. 30, 2017

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

Incentive Compensation

INCENTIVE COMPENSATION

On January 7, 2017, the Compensation Committee of the Board of Directors of the Partnership’s general partner (the “Board”) approved a special grant of 312,825 restricted common units to Thomas L. Carter, Jr., the President and Chief Executive Officer of the Partnership’s general partner. Such restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.

On January 11, 2017, each non-employee director on the Board, other than Robert E. W. Sinclair, was granted 9,095 fully vested common units for service during 2016. Mr. Sinclair was granted 3,653 fully vested common units for services during 2016 prior to his resignation from the Board. On July 28, 2017, Mr. William Randall, the newly elected member of the Board, was issued 6,426 fully vested common units.

On February 15, 2017, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted of 438,067 restricted common units and 438,067 restricted performance units (in the form of phantom units) with distribution equivalent rights. The restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.

The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016, respectively:



	Three Months Ended September 30,				Nine Months Ended September 30,
Incentive compensation expense	2017		2016		2017		2016
	(In thousands)				(In thousands)
Cash—long-term incentive plan	$	359	$	580	$	995	$	2,990
Equity-based compensation—restricted common and subordinated units	3,364		4,487		10,246		10,420
Equity-based compensation—restricted performance units	3,767		3,066		6,710		11,105
Board of Directors incentive plan	544		428		1,658		1,385
Total incentive compensation expense	$	8,034	$	8,561	$	19,609	$	25,900

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References + Details

Redeemable Preferred Units	9 Months Ended
Redeemable Preferred Units	Sep. 30, 2017
Equity [Abstract]
Redeemable Preferred Units	REDEEMABLE PREFERRED UNITS The Partnership had 26,426 and 52,691 redeemable preferred units outstanding with a carrying value of $27.1 million and $54.0 million as of September 30, 2017 and December 31, 2016, respectively. The aforementioned amounts included accrued distributions of $0.7 million as of September 30, 2017 and $1.3 million as of December 31, 2016. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The redeemable preferred units are entitled to an annual distribution of 10% of the outstanding funded capital of the redeemable preferred units, payable on a quarterly basis in arrears. The redeemable preferred units are convertible into common and subordinated units at any time at the option of the redeemable preferred unitholders. The redeemable preferred units have 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. The redeemable preferred unitholders can elect to have the Partnership redeem, at face value, all remaining redeemable preferred units as of December 31, 2017, plus any accrued and unpaid distributions. All redeemable preferred units not redeemed as of 2017 year end shall automatically convert to common and subordinated units during the first quarter of 2018. For the nine months ended September 30, 2017, 19,641 redeemable preferred units were redeemed for $20.1 million, including accrued unpaid yield, and 6,624 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. For the year ended December 31, 2016, 6,064 redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjusted basis.

Earnings Per Unit

9 Months Ended

Sep. 30, 2017

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 redeemable preferred units could be converted into 0.8 million common units and 1.0 million subordinated units as of September 30, 2017. At September 30, 2017, if the outstanding redeemable preferred units were converted to common and subordinated units, the effect would be anti-dilutive. 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 September 30, 2017, there were no 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:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands, except per unit amounts)						(In thousands, except per unit amounts)
NET INCOME (LOSS)	$	22,034		$	37,535		$	137,793		$	27,474
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	20			8			27			15
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(666		)	(1,324		)	(2,452		)	(4,439		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	21,388		$	36,219		$	135,368		$	23,050
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—		$	—		$	—
Common units	16,371			23,114			83,989			24,343
Subordinated units	5,017			13,105			51,379			(1,293		)
	$	21,388		$	36,219		$	135,368		$	23,050
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (basic)	101,623			95,740			97,777			95,086
Per subordinated unit (basic)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (basic)	95,388			95,189			95,269			95,125
Per common unit (diluted)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (diluted)	101,623			96,011			97,777			95,619
Per subordinated unit (diluted)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (diluted)	95,388			95,189			95,269			95,467

AT-THE-MARKET OFFERING PROGRAM	9 Months Ended
AT-THE-MARKET OFFERING PROGRAM	Sep. 30, 2017
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 Securities and Exchange Commission 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. Through September 30, 2017, the Partnership sold 1.9 million common units under the ATM Program for net proceeds of $31.3 million.

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Subsequent Events	9 Months Ended
Subsequent Events	Sep. 30, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS On November 1, 2017, the Partnership amended and restated its credit agreement, as discussed further in Note 7—Credit Facility. On November 6, 2017, the Board approved a distribution for the three months ended September 30, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on November 24, 2017 to unitholders of record at the close of business on November 17, 2017. Additionally, on November 6, 2017, the Partnership entered into oil and natural gas commodity derivative contracts, as summarized in Note 5—Derivatives and Financial Instruments.

Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

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 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. 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.

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. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year.

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 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 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.

New Accounting Pronouncements


•	The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.


•	The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.


•	The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.

Earnings Per Unit

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation Liability

The following table describes changes to the Partnership’s ARO liability during the period:



	For the nine months ended
	September 30, 2017
	(In thousands)
Beginning asset retirement obligations	$	13,350
Liabilities incurred	290
Liabilities settled	(113		)
Accretion expense	760
Dispositions	(5		)
Revisions	(71		)
Ending asset retirement obligations	$	14,211
Current asset retirement obligations	$	302
Non-current asset retirement obligations	$	13,909

Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Schedule of Fair Values of the Properties Acquired

The following table summarizes the fair values assigned to the properties acquired:



	Proved		Unproved		Net Working Capital		ARO			Total Fair Value		Cash
	(in thousands)
June	$	39,735	$	79,827	$	2,064	$	(50	)	$	121,576	$	121,576

The following table summarizes the asset acquisitions which included producing properties:



	Proved		Unproved		Net Working Capital		Total Fair Value		Acquisition-Related Costs¹		Cash		Fair Value of Common Units Issued
	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	1,162	$	27,380	$	12,026
June	5,006		45,477		—		50,483		1,468		4,802		45,681
August	3,277		9,984		—		13,261		89		4,289		8,972
September	3,120		—		—		3,120		—		3,120		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	2,719	$	39,591	$	66,679

¹ Acquisition-related costs were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.

In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as follows:



	Unproved		Cash		Fair Value of Common Units Issued
	(in thousands)
Q1 2017	$	21,189	$	21,017	$	172
Q2 2017	13,329		13,329		—
Q3 2017	19,946		15,205		4,741
	$	54,464	$	49,551	$	4,913

Derivatives and Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative [Line Items]

Summary of Fair Value and Classification of Derivative Instruments

The table below summarizes the fair value and classification of the Partnership’s derivative instruments:



As of September 30, 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	$	5,338	$	(614	)	$	4,724
Long-term asset	Deferred charges and other long-term assets	1,822		(217		)	1,605
Total assets		$	7,160	$	(831	)	$	6,329
Liabilities:
Current liability	Commodity derivative liabilities	$	614	$	(614	)	$	—
Long-term liability	Commodity derivative liabilities	217		(217		)	—
Total liabilities		$	831	$	(831	)	$	—



As of December 31, 2016
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	$	3,879	$	(3,879	)	$	—
Long-term asset	Deferred charges and other long-term assets	—		—			—
Total assets		$	3,879	$	(3,879	)	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	20,116	$	(3,879	)	$	16,237
Long-term liability	Commodity derivative liabilities	482		—			482
Total liabilities		$	20,598	$	(3,879	)	$	16,719

Changes in Fair Value of Company's Commodity Derivative Instruments

Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows:



	For the Nine Months Ended September 30,
Derivatives not designated as hedging instruments	2017			2016
	(In thousands)
Beginning fair value of commodity derivative instruments	$	(16,719	)	$	64,534
Gain (loss) on oil derivative instruments	18,306			(8,906		)
Gain (loss) on natural gas derivative instruments	17,081			(3,389		)
Net cash received on settlements of oil derivative instruments	(10,682		)	(23,034		)
Net cash received on settlements of natural gas derivative instruments	(1,657		)	(16,186		)
Net change in fair value of commodity derivative instruments	23,048			(51,515		)
Ending fair value of commodity derivative instruments	$	6,329		$	13,019

Oil and Natural Gas

Derivative [Line Items]

Summary of Open Derivative Contracts

The Partnership had the following open derivative contracts for oil as of September 30, 2017:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2017
Third Quarter	172,000	$	53.31	$	52.40	$	55.23
Fourth Quarter	687,000	53.21		52.02		55.23
2018
First Quarter	611,000	$	54.18	$	52.09	$	55.05
Second Quarter	573,000	54.16		52.09		54.90
Third Quarter	541,000	54.16		51.85		54.90
Fourth Quarter	502,000	54.22		51.85		54.90

The Partnership had the following open derivative contracts for natural gas as of September 30, 2017:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2017
Fourth Quarter	13,130,000	$	3.13	$	2.92	$	3.57
2018
First Quarter	12,570,000	$	3.06	$	2.96	$	3.45
Second Quarter	11,340,000	3.03		2.86		3.23
Third Quarter	9,630,000	3.02		2.90		3.23
Fourth Quarter	8,210,000	3.01		2.90		3.23

Subsequent to September 30, 2017, the Partnership entered into the following oil derivative contracts:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2017
Fourth Quarter	30,000	$	56.51	$	55.87	$	57.15
2018
First Quarter	130,000	$	55.02	$	53.99	$	57.15
Second Quarter	175,000	54.73		53.99		56.75
Third Quarter	215,000	54.71		53.99		55.87
Fourth Quarter	255,000	54.22		52.82		55.87
2019
First Quarter	165,000	$	53.58	$	52.82	$	54.02
Second Quarter	165,000	53.58		52.82		54.02
Third Quarter	165,000	53.58		52.82		54.02
Fourth Quarter	165,000	53.58		52.82		54.02

Additionally, subsequent to September 30, 2017, the Partnership entered into the following natural gas derivative contracts:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
First Quarter	1,020,000	$	3.11	$	3.01	$	3.21
Second Quarter	2,320,000	3.00		2.93		3.04
Third Quarter	3,970,000	3.00		2.93		3.04
Fourth Quarter	5,420,000	3.00		2.92		3.04
2019
First Quarter	3,600,000	$	2.91	$	2.90	$	2.93
Second Quarter	3,600,000	2.91		2.90		2.93
Third Quarter	3,600,000	2.91		2.90		2.93
Fourth Quarter	3,600,000	2.91		2.90		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
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+ Details

Fair Value Measurement (Tables)

9 Months Ended

Sep. 30, 2017

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
	Level 1		Level 2		Level 3		Effect of Counterparty Netting			Total
	(In thousands)
As of September 30, 2017
Financial Assets
Commodity derivative instruments	$	—	$	7,160	$	—	$	(831	)	$	6,329
Financial Liabilities
Commodity derivative instruments	$	—	$	831	$	—	$	(831	)	$	—
As of December 31, 2016
Financial Assets
Commodity derivative instruments	$	—	$	3,879	$	—	$	(3,879	)	$	—
Financial Liabilities
Commodity derivative instruments	$	—	$	20,598	$	—	$	(3,879	)	$	16,719

Schedule of Assets Measured at Fair Value on a Nonrecurring Basis

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



	Fair Value Measurements Using¹							Net Book Value¹
	Level 1			Level 2		Level 3		Net Book Value¹		Impairment
	(In thousands)
Three months ended September 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Three months ended September 30, 2016
Impaired oil and natural gas properties	$	—		$	—	$	—	$	—	$	—
Nine months ended September 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Nine months ended September 30, 2016
Impaired oil and natural gas properties	$	—	—	$	—	$	3,042	$	9,817	$	6,775

¹Amounts represent value on the dates of assessment.

Incentive Compensation (Tables)

9 Months Ended

Sep. 30, 2017

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

Summary of Incentive Compensation Expense



	Three Months Ended September 30,				Nine Months Ended September 30,
Incentive compensation expense	2017		2016		2017		2016
	(In thousands)				(In thousands)
Cash—long-term incentive plan	$	359	$	580	$	995	$	2,990
Equity-based compensation—restricted common and subordinated units	3,364		4,487		10,246		10,420
Equity-based compensation—restricted performance units	3,767		3,066		6,710		11,105
Board of Directors incentive plan	544		428		1,658		1,385
Total incentive compensation expense	$	8,034	$	8,561	$	19,609	$	25,900

Earnings Per Unit (Tables)

9 Months Ended

Sep. 30, 2017

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:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands, except per unit amounts)						(In thousands, except per unit amounts)
NET INCOME (LOSS)	$	22,034		$	37,535		$	137,793		$	27,474
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	20			8			27			15
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(666		)	(1,324		)	(2,452		)	(4,439		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	21,388		$	36,219		$	135,368		$	23,050
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—		$	—		$	—
Common units	16,371			23,114			83,989			24,343
Subordinated units	5,017			13,105			51,379			(1,293		)
	$	21,388		$	36,219		$	135,368		$	23,050
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (basic)	101,623			95,740			97,777			95,086
Per subordinated unit (basic)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (basic)	95,388			95,189			95,269			95,125
Per common unit (diluted)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (diluted)	101,623			96,011			97,777			95,619
Per subordinated unit (diluted)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (diluted)	95,388			95,189			95,269			95,467

Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions		9 Months Ended
	May 06, 2015 USD ($) $ / shares shares	Sep. 30, 2017 basin state shares
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]
Units exchanged in merger (in shares)	72,574,715	4,341,000
Capital units converted upon merger (in shares)		201,000
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 for initial public offering, net of offering costs, units	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)		263,000
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]
Units conversion ratio as part of merger	1
Capital units converted upon merger (in shares)	117,963

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations			$ 13,350
Liabilities incurred			290
Liabilities settled			(113)
Accretion expense	$ 260	$ 206	760	$ 680
Dispositions			(5)
Revisions			(71)
Ending asset retirement obligations	14,211		14,211
Other current liabilities	302		302		$ 0
Non-current asset retirement obligations	$ 13,909		$ 13,909		$ 13,350

Acquisitions and Dispositions - Additional Information (Details) $ in Millions		9 Months Ended
	Feb. 21, 2017 USD ($) well phase	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Business Acquisition [Line Items]
Payments to acquire oil, mineral, and royalty interests			$ 1.0
Permian Basin
Business Acquisition [Line Items]
Payments to acquire oil, mineral, and royalty interests		$ 10.0
Midland Basin
Business Acquisition [Line Items]
Payments to acquire oil, mineral, and royalty interests		$ 8.3
Angelina County, Texas \| Farmout Agreement
Business Acquisition [Line Items]
Ownership interest in the acreage, percent	50.00%
Number of wells anticipated to be drilled \| well	18
Additional wells to be drilled \| well	20
Number of phases \| phase	3
Angelina County, Texas \| Farmout Agreement \| Canaan Resource Partners
Business Acquisition [Line Items]
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%
Angelina County, Texas \| Farmout Agreement \| Minimum
Business Acquisition [Line Items]
Anticipated reduction in capital obligations, next 12 months	$ 30.0
Anticipated reduction in capital obligations, annually	40.0
Angelina County, Texas \| Farmout Agreement \| Maximum
Business Acquisition [Line Items]
Anticipated reduction in capital obligations, next 12 months	35.0
Anticipated reduction in capital obligations, annually	$ 50.0

Acquisitions and Dispositions - Schedule of Fair Values of the Properties Acquired (Details) - USD ($)	1 Months Ended				3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 30, 2017	Aug. 31, 2017	Jun. 30, 2017	Jan. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Sep. 30, 2017	Sep. 29, 2017
Delaware Basin And East Texas
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 3,120,000	$ 3,277,000	$ 5,006,000	$ 5,135,000					$ 16,538,000
Unproved oil and natural gas properties	0	9,984,000	45,477,000	34,008,000					89,469,000
Net working capital	0	0	0	263,000					263,000
Total fair value	3,120,000	13,261,000	50,483,000	39,406,000					106,270,000
Acquisition related costs	0	89,000	1,468,000	1,162,000					2,719,000
Cost incurred, acquired cash	39,591,000	4,289,000	4,802,000	27,380,000	$ 39,591,000	$ 4,802,000			39,591,000	$ 3,120,000
Fair value common units issued	0	$ 8,972,000	45,681,000	$ 12,026,000					66,679,000
East Texas
Business Acquisition [Line Items]
Unproved oil and natural gas properties					19,946	13,329	$ 21,189		54,464
Cost incurred, acquired cash	$ 49,551		$ 13,329		49,551	13,329	21,017		49,551	$ 15,205
Fair value common units issued					$ 4,741	$ 0	$ 172		$ 4,913
DJ Basin
Business Acquisition [Line Items]
Proved oil and natural gas properties								$ 39,735,000
Unproved oil and natural gas properties								79,827,000
Net working capital								2,064,000
Asset retirement obligations								(50,000)
Total fair value								121,576,000
Cost incurred, acquired cash								$ 121,576,000

Derivatives and Financial Instruments - Additional Information (Details) $ in Millions	Sep. 30, 2017 USD ($) counterparty
Derivative [Line Items]
Number of counterparties	9
Senior Line of Credit
Derivative [Line Items]
Number of counterparties	7
Fair value of risk exposure \| $	$ 7.2

Derivatives and Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets		$ 3,879
Effect of Counterparty Netting, Assets	$ (831)	(3,879)
Net Carrying Value on Balance Sheet, Assets	6,329	0
Gross Fair Value, Liabilities		20,598
Effect of Counterparty Netting, Liabilities	(831)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	0	16,719
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	5,338	3,879
Effect of Counterparty Netting, Assets	(614)	(3,879)
Net Carrying Value on Balance Sheet, Assets	4,724	0
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross Fair Value, Assets	1,822	0
Effect of Counterparty Netting, Assets	(217)	0
Net Carrying Value on Balance Sheet, Assets	1,605	0
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	614	20,116
Effect of Counterparty Netting, Liabilities	(614)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	0	16,237
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross Fair Value, Liabilities	217	482
Effect of Counterparty Netting, Liabilities	(217)	0
Net Carrying Value on Balance Sheet, Liabilities	$ 0	$ 482

Derivatives and Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (9,341)	$ 7,813	$ 35,387	$ (12,295)
Net cash received on settlements of derivative instruments			(12,339)	(39,220)
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments			(16,719)	64,534
Net change in fair value of commodity derivative instruments			23,048	(51,515)
Ending fair value of commodity derivative instruments	$ 6,329	$ 13,019	6,329	13,019
Oil \| Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments			18,306	(8,906)
Net cash received on settlements of derivative instruments			(10,682)	(23,034)
Natural Gas \| Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments			17,081	(3,389)
Net cash received on settlements of derivative instruments			$ (1,657)	$ (16,186)

Fair Value Measurement - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross Fair Value, Assets		$ 3,879
Effect of Counterparty Netting, Assets	$ (831)	(3,879)
Net Carrying Value on Balance Sheet, Assets	6,329	0
Gross Fair Value, Liabilities		20,598
Effect of Counterparty Netting, Liabilities	(831)	(3,879)
Net Carrying Value on Balance Sheet, Liabilities	0	16,719
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		(3,879)
Net Carrying Value on Balance Sheet, Assets	6,329	0
Effect of Counterparty Netting, Liabilities		(3,879)
Net Carrying Value on Balance Sheet, Liabilities	0	16,719
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	7,160	3,879
Gross Fair Value, Liabilities	$ 831	$ 20,598

Fair Value Measurement - Schedule of Assets Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Impairment	$ 0	$ 0	$ 0	$ 6,775
Fair Value Measurements, Nonrecurring Basis
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	0		0	0
Impaired oil and natural gas properties, Net Book Value	0	0	0	9,817
Impaired oil and natural gas properties, Impairment	0	0	0	6,775
Fair Value Measurements, Nonrecurring Basis \| Level 1
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	0	0	0	0
Fair Value Measurements, Nonrecurring Basis \| Level 2
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	0	0	0	0
Fair Value Measurements, Nonrecurring Basis \| Level 3
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Impaired oil and natural gas properties, Fair Value Measurements	$ 0	$ 0	$ 0	$ 3,042

Credit Facility - Additional Information (Details)			9 Months Ended
Credit Facility - Additional Information (Details)	Nov. 01, 2017	Oct. 31, 2016 USD ($)	Sep. 30, 2017 USD ($)	Apr. 25, 2017 USD ($)	Dec. 31, 2016 USD ($)	Apr. 15, 2016 USD ($)
Line Of Credit Facility [Line Items]
Credit facility			$ 362,000,000		$ 316,000,000
Senior Line of Credit \| Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity			$ 1,000,000,000
Borrowing base		$ 500,000,000		$ 550,000,000		$ 450,000,000
Interest payable, term			90 days
Weighted average interest rate (percent)			3.74%		3.26%
Borrowing base threshold (percent)			50.00%
Credit facility			$ 362,000,000		$ 316,000,000
Unused portion of current borrowing base			$ 188,000,000		$ 184,000,000
Senior Line of Credit \| Revolving Credit Facility \| Federal funds effective rate
Line Of Credit Facility [Line Items]
Interest rate (percent)			0.50%
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]
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%	1.50%
Senior Line of Credit \| Revolving Credit Facility \| Minimum \| Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		1.00%	0.50%
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%	2.50%
Senior Line of Credit \| Revolving Credit Facility \| Maximum \| Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		2.00%	1.50%
Subsequent Event \| Senior Line of Credit \| Revolving Credit Facility
Line Of Credit Facility [Line Items]
Interest payable, term	5 years

Incentive Compensation - Additional Information (Details) - shares	Jul. 28, 2017	Feb. 15, 2017	Jan. 11, 2017	Jan. 07, 2017
Common Units \| President and CEO
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested (in shares)				312,825
Common Units \| Non-employee Directors \| Non-Employee Director on the Board other than Robert E. W. Sinclair
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested (in shares)			9,095
Common Units \| Non-employee Directors \| Robert E. W. Sinclair
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested (in shares)			3,653
Common Units \| Non-employee Directors \| William Randall
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units, fully vested (in shares)	6,426
Restricted Common Units \| 2015 LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units (in shares)		438,067
Restricted Performance Units \| 2015 LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant of stock units (in shares)		438,067

Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash—long-term incentive plan	$ 359	$ 580	$ 995	$ 2,990
Total incentive compensation expense	8,034	8,561	19,609	25,900
Restricted common and subordinated units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	3,364	4,487	10,246	10,420
Restricted Performance Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation	3,767	3,066	6,710	11,105
Board of Directors \| Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total incentive compensation expense	$ 544	$ 428	$ 1,658	$ 1,385

Redeemable Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017 USD ($) $ / shares shares	Dec. 31, 2016 USD ($) shares
Class of Stock [Line Items]
Preferred units, outstanding value \| $	$ 27,092	$ 54,015
Preferred Units
Class of Stock [Line Items]
Partners' equity, preferred units, outstanding (in shares) \| shares	26,426	52,691
Preferred units, outstanding value \| $	$ 27,100	$ 54,000
Accrued distributions \| $	$ 700	$ 1,300
Preferred units distribution rate	10.00%
Adjusted conversion price (in us dollars per share) \| $ / shares	$ 14.2683
Preferred units, redeemed (in shares) \| shares	19,641
Payments redeem preferred units \| $	$ 20,100
Number of preferred units converted (in shares) \| shares	6,624	6,064
Conversion of preferred units to common units \| $	$ 6,600	$ 6,100
Common Units
Class of Stock [Line Items]
Adjusted conversion rate	30.3431
Conversion of preferred units (in shares) \| shares	200,996	184,006
Subordinated Units
Class of Stock [Line Items]
Adjusted conversion rate	39.7427
Conversion of preferred units (in shares) \| shares	263,247	240,986

Earnings Per Unit - Additional Information (Details) shares in Millions	9 Months Ended
	Sep. 30, 2017 shares
Common Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	0.8
Subordinated Units
Earnings Per Share Basic [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU	1.0

Earnings Per Unit - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share Basic [Line Items]
Net income (loss)	$ 22,034	$ 37,535	$ 137,793	$ 27,474
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	20	8	27	15
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(666)	(1,324)	(2,452)	(4,439)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	21,388	36,219	135,368	23,050
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	21,388	36,219	135,368	23,050
Common Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 16,371	$ 23,114	$ 83,989	$ 24,343
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.16	$ 0.24	$ 0.86	$ 0.26
Weighted average units outstanding (basic) (in shares)	101,623	95,740	97,777	95,086
Per unit (diluted) (in dollars per share)	$ 0.16	$ 0.24	$ 0.86	$ 0.26
Weighted average units outstanding (diluted) (in shares)	101,623	96,011	97,777	95,619
Subordinated Units
ALLOCATION OF NET INCOME (LOSS):
Allocation of net income (loss)	$ 5,017	$ 13,105	$ 51,379	$ (1,293)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per unit (basic) (in dollars per share)	$ 0.05	$ 0.14	$ 0.54	$ (0.01)
Weighted average units outstanding (basic) (in shares)	95,388	95,189	95,269	95,125
Per unit (diluted) (in dollars per share)	$ 0.05	$ 0.14	$ 0.54	$ (0.01)
Weighted average units outstanding (diluted) (in shares)	95,388	95,189	95,269	95,467

AT-THE-MARKET OFFERING PROGRAM (Details) - USD ($) shares in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	May 26, 2017
Class of Stock [Line Items]
Proceeds from sale of common units	$ 31,267,000	$ 0
Common Units
Class of Stock [Line Items]
Equity Distribution Agreement, maximum value			$ 100,000,000
Number of common units sold, units	1.9
Proceeds from sale of common units	$ 31,300,000

Subsequent Events - Additional Information (Details) - Subsequent Event	Nov. 06, 2017 $ / shares
Common Units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in usd per unit)	$ 0.3125
Subordinated Units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in usd per unit)	$ 0.20875

Derivatives and 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	1 Months Ended	9 Months Ended
	Nov. 07, 2017 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2017 MMBTU $ / MMBTU $ / bbl bbl
Third Quarter 2017 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl		172
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		53.31
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		52.40
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		55.23
Fourth Quarter 2017 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl		687
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		53.21
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		52.02
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		55.23
Fourth Quarter 2017 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU		13,130
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU		3.13
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU		2.92
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU		3.57
First Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl		611
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		54.18
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		52.09
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		55.05
First Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU		12,570
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU		3.06
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU		2.96
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU		3.45
Second Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl		573
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		54.16
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		52.09
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		54.90
Second Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU		11,340
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU		3.03
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		541
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		54.16
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		51.85
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		54.90
Third Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU		9,630
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		2.90
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		502
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)		54.22
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)		51.85
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)		54.90
Fourth Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU		8,210
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
Subsequent Event \| Fourth Quarter 2017 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	30
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	56.51
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	55.87
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	57.15
Subsequent Event \| First Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	130
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	55.02
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	53.99
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	57.15
Subsequent Event \| First Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	1,020
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.11
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	3.01
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.21
Subsequent Event \| Second Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	175
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	54.73
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	53.99
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	56.75
Subsequent Event \| Second Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	2,320
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.00
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.04
Subsequent Event \| Third Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	215
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	54.71
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	53.99
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	55.87
Subsequent Event \| Third Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	3,970
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.00
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.93
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.04
Subsequent Event \| Fourth Quarter 2018 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	255
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	54.22
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	55.87
Subsequent Event \| Fourth Quarter 2018 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	5,420
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	3.00
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) \| $ / MMBTU	2.92
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) \| $ / MMBTU	3.04
Subsequent Event \| First Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	165
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	53.58
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	54.02
Subsequent Event \| First Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	3,600
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.91
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	2.93
Subsequent Event \| Second Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	165
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	53.58
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	54.02
Subsequent Event \| Second Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	3,600
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.91
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	2.93
Subsequent Event \| Third Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	165
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	53.58
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	54.02
Subsequent Event \| Third Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	3,600
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.91
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	2.93
Subsequent Event \| Fourth Quarter 2019 \| Oil
Derivative [Line Items]
Derivative Contract, Volume (in Bbl) \| bbl	165
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu)	53.58
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu)	52.82
Derivative Contract, Price Range High (in USD per Bbl or MMBtu)	54.02
Subsequent Event \| Fourth Quarter 2019 \| Natural Gas
Derivative [Line Items]
Derivative Contract, Volume (in MMBtu) \| MMBTU	3,600
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) \| $ / MMBTU	2.91
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	2.93

Commitments and Contingencies - Additional Information (Details)	Sep. 30, 2017 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Provision for remediation costs	$ 0