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Incentive Compensation

INCENTIVE COMPENSATION

Overview

The board of directors of the Partnership’s general partner (the "Board") established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to the Partnership’s common units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vesting terms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof.

Incentive compensation expense is included in General and administrative expense on the consolidated statements of operations. The total compensation expense related to common unit grants is measured as the number of units granted that are expected to vest multiplied by the grant-date fair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the award agreements over the requisite service periods (generally equivalent to the vesting period).

Cash Awards

The Partnership may also provide from time to time short-term and long-term cash incentive and retention awards annually for its directors, executive officers, and certain other employees. Certain employees are entitled to receive cash bonuses based on service criteria over a four-year requisite service period ending in 2019. Payments are disbursed as vesting is attained on a graded annual basis. The last grant of such cash awards with graded vesting requirements was made in 2016 with vestings extending through December 31, 2019.

Restricted Unit Awards

Restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Award recipients have all the rights of a unitholder in the Partnership, including the right to receive distributions thereon, if and when made by the Partnership. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method.

In conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the executive officers of the Partnership's general partner, certain other employees, and each of the non-employee directors of the Partnership’s general partner. The grants included restricted common units subject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements that extended through March 15, 2019.

The Compensation Committee of the Board (the "Compensation Committee") annually approves a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees. Consistent with previous awards the 2019 grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2022. In January of each year, non-employee directors of the Partnership’s general partner receive compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service.

The following table summarizes information about restricted units for the year ended December 31, 2019.


	Number of Units	Weighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2018	1,334,016	$	17.29
Granted	496,316	17.09
Vested	(778,956)	16.64
Converted	—	—
Forfeited	(13,117)	17.49
Unvested at December 31, 2019	1,038,259	17.67

The weighted-average grant-date fair value per unit for unit-based awards was $17.09, $17.95, and $18.48 for the years ended December 31, 2019, 2018, and 2017, respectively. As of December 31, 2019, unrecognized compensation cost associated with restricted unit awards was $8.5 million, which the Partnership expects to recognize over a weighted-average period of 1.67 years. The fair value of units vested for the years ended December 31, 2019, 2018, and 2017 was $12.7 million, $12.9 million, and $25.1 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2019, 2018, and 2017.

Performance Unit Awards

The Compensation Committee also approves grants of restricted performance units that are subject to both performance-based and service-based vesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Partnership’s performance over each of the three calendar year performance periods commencing January 1 of the first calendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metrics are achieved. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate, are probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital.

The following table summarizes information about performance units for the year ended December 31, 2019.


Performance units	Number of Units	Weighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2018	1,811,810	$	15.94
Granted¹	953,638	16.84
Vested	(1,378,188)	14.83
Forfeited	(18,178)	17.63
Unvested at December 31, 2019	1,369,082	17.66

¹ Includes 457,322 of additional performance units issued based on the final performance multiplier for awards that vested in the period.

The weighted-average grant-date fair value per unit for performance unit awards was $16.84, $17.94, and $17.99 for the years ended December 31, 2019, 2018, and 2017, respectively. Unrecognized compensation cost associated with performance unit awards was $6.3 million as of December 31, 2019, which the Partnership expects to recognize over a weighted-average period of 1.82 years. The fair value of performance units vested for the years ended December 31, 2019, and 2018 was $22.7 million, and $1.5 million, respectively. No performance units vested for the year ended December 31, 2017.

Incentive Compensation

The table below summarizes incentive compensation expense recorded in General and administrative expenses in the consolidated statements of operations for the years ended December 31, 2019, 2018, and 2017.


	Year Ended December 31,
Incentive compensation expense	2019		2018		2017
	(In thousands)
Cash — short and long-term incentive plan	$	5,593	$	9,301	$	4,373
Equity-based compensation — restricted common and subordinated units	10,751		13,624		13,476
Equity-based compensation — restricted performance units	7,386		14,188		17,367
Board of Directors incentive plan	2,347		2,322		2,202
Total incentive compensation expense	$	26,077	$	39,435	$	37,418

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2019
Retirement Benefits [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANSBlack Stone Natural Resources Management Company, a subsidiary of the Partnership, sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred contributions up to 90% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Partnership makes matching contributions of 100% of employee contributions, up to 5% of compensation. These matching contributions are subject to a graded vesting schedule, with 33% vested after one year, 66% vested after two years and 100% vested after three years of service with the Partnership. Following three years of service, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.7 million, $0.7 million, and $0.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2019
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 recorded. Put Option Related to Noble Acquisition By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 45.33% and 42.63% of the mineral interests held of record by Holdings and Temin, respectively, as of December 31, 2019. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2019, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded. Litigation From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of December 31, 2019 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations.

Preferred Units	12 Months Ended
Preferred Units	Dec. 31, 2019
Equity [Abstract]
Redeemable Preferred Units	PREFERRED UNITS Series A Redeemable Preferred Units As of December 31, 2019 and 2018, there were no Series A redeemable preferred units outstanding. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears. The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit. The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. For the year ended December 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017. For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield, and 6,624 Series A redeemable preferred units totaling $6.6 million were converted into the equivalent of 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million. The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926. The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $298.4 million, including accrued distributions of $5.3 million, as of December 31, 2019 and 2018. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain redemption provisions are outside the control of the Partnership.

Earnings Per Unit

12 Months Ended

Dec. 31, 2019

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 units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common 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 Partnership assesses the Series A redeemable preferred units and the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU. 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.

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


	For the Year Ended December 31,
	2019		2018		2017
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	214,368	$	295,560	$	157,153
Net (income) loss attributable to noncontrolling interests	—		(24)		34
Distributions on Series A redeemable preferred units	—		(25)		(3,117)
Distributions on Series B cumulative convertible preferred units	(21,000)		(21,000)		(1,925)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	193,368	$	274,511	$	152,145
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—
Common units	169,375		154,662		98,389
Subordinated units	23,993		119,849		53,756
	$	193,368	$	274,511	$	152,145
Weighted average common units outstanding:
Weighted average common units outstanding (basic)	168,230		106,064		97,400
Effect of dilutive securities	146		15,200		—
Weighted average common units outstanding (diluted)	168,376		121,264		97,400
Weighted average subordinated units outstanding:
Weighted average subordinated units outstanding (basic)	37,740		96,099		95,149
Effect of dilutive securities	—		247		—
Weighted average subordinated units outstanding (diluted)	37,740		96,346		95,149
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	1.01	$	1.46	$	1.01
Per subordinated unit (basic)	0.64		1.25		0.56
Per common unit (diluted)¹	1.01		1.45		1.01
Per subordinated unit (diluted)²	0.64		1.25		0.56

¹For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $21.0 million.

²For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $0.3 million.

The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:


	For the Year Ended December 31,
	2019	2018	2017
	(in thousands)
Potentially dilutive securities (common units):
Series A redeemable preferred units on an as-converted basis	—	189	996
Series B cumulative convertible preferred units on an as-converted basis	14,968	—	1,612
	14,968	189	2,608

Potentially dilutive securities (subordinated units):
Series A redeemable preferred units on an as-converted basis	—	—	1,304

Common and Subordinated Units

12 Months Ended

Dec. 31, 2019

Common and Subordinated Units

COMMON AND SUBORDINATED UNITS

Common and Subordinated Units

The common units and subordinated units represent limited partner interests in the Partnership. The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control may not vote on any matter.

The holders of common units are and, prior to the end of the subordination period (as defined in the Partnership agreement), the subordinated units were, entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units, respectively, under the partnership agreement. The subordination period under the partnership agreement ended on the first business day after the Partnership earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there were no outstanding arrearages on the common units. This test was met upon the payment of the distribution for the first quarter of 2019. Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and the priority right of the common unitholders ceased to exist.

The partnership agreement generally provides that any distributions are paid each quarter in the following manner:

•first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments; and

•second, to the holders of common units.

The following table provides information about the Partnership's per unit distributions to common and subordinated unitholders:


	Year Ended December 31,
	2019		2018		2017
DISTRIBUTIONS DECLARED AND PAID:
Per common unit	$	1.48	$	1.33	$	1.20
Per subordinated unit¹	0.74		1.13		0.79

¹For the six months ended December 31, 2019 there were no distributions on subordinated units as all subordinated units converted into common units on May 24, 2019.

Common Unit Repurchase Program

On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. In 2019, the Partnership repurchased a total of 136,665 common units for an aggregate cost of $2.2 million. As of December 31, 2019, the Partnership has repurchased $4.2 million in common units under the repurchase program since inception. The repurchase program is funded from the Partnership's cash on hand or availability under the Credit Facility. Any repurchased units are canceled.

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 amount 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.

The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.

For the year ended December 31, 2019, the Partnership sold no common units under the ATM Program. For the year ended December 31, 2018, the Partnership sold 2,243,775 common units under the ATM Program for net proceeds of $40.5 million. For the year ended December 31, 2017, the Partnership sold 2,001,823 common units under the ATM Program for net proceeds of $32.5 million.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Distribution On February 5, 2020, the Board approved a distribution for the period from October 1, 2019 to December 31, 2019 of $0.30 per common unit. Distributions were paid on February 24, 2020 to unitholders of record at the close of business on February 17, 2020. General and Administrative Expense Reductions The Partnership has taken significant steps to reduce its general and administrative expenses, including broad workforce reductions and lower Board and executive compensation levels. The Partnership expects to incur a one-time cash charge of approximately $5 million in the first quarter of 2020 associated with severance agreements for affected employees.

Supplemental Oil and Natural Gas Disclosures

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Oil and Natural Gas Disclosure - Unaudited

Geographic Area of Operation

All the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Texas, Louisiana, and North Dakota. However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves are presented on a consolidated basis.

Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:


	Year Ended December 31,
	2019		2018		2017
	(in thousands)
Acquisition Costs of Properties¹:
Proved	$	2,288	$	13,438	$	96,596
Unproved	41,643		136,079		383,535
Exploration Costs	3		13,544		618
Development Costs¹	34,617		165,198		81,056
Total	$	78,551	$	328,259	$	561,805

¹See Note 4 – Oil and Natural Gas Properties for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below:


	As of December 31,
	2019		2018
	(in thousands)
Proved properties¹	$	2,228,893	$	2,377,305
Unproved properties	1,073,447		1,063,883
Total	3,302,340		3,441,188
Accumulated depreciation, depletion, amortization, and impairment	(1,870,412)		(1,865,692)
Oil and natural gas properties, net	$	1,431,928	$	1,575,496

¹Proved properties include capitalized costs related to farmout wells not yet assigned.

Oil and Natural Gas Reserve Information

The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.


	Crude Oil (MBbl)	Natural Gas (MMcf)	Total (MBoe)
Net proved reserves at December 31, 2016	18,368	270,339	63,425
Revisions of previous estimates¹	(2,298)	14,505	120
Purchases of minerals in place²	2,335	31,323	7,555
Extensions, discoveries and other additions³	3,046	43,886	10,360
Production	(3,552)	(59,779)	(13,515)
Net proved reserves at December 31, 2017	17,899	300,274	67,945
Revisions of previous estimates¹	(35)	(11,027)	(1,873)
Purchases of minerals in place⁴	227	419	297
Extensions, discoveries and other additions³	4,438	95,976	20,434
Production	(4,962)	(71,622)	(16,899)
Net proved reserves at December 31, 2018	17,567	314,020	69,904
Revisions of previous estimates¹	951	19,136	4,140
Purchases of minerals in place⁴	46	279	92
Extensions, discoveries and other additions³	3,263	53,158	12,123
Production	(4,777)	(77,635)	(17,716)
Net proved reserves at December 31, 2019	17,050	308,958	68,543
Net Proved Developed Reserves⁵
December 31, 2017	17,891	233,017	56,727
December 31, 2018	17,567	278,233	63,939
December 31, 2019	17,050	263,371	60,945
Net Proved Undeveloped Reserves⁶
December 31, 2017	8	67,257	11,218
December 31, 2018	—	35,787	5,965
December 31, 2019	—	45,587	7,598

¹Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells.

²Includes the acquisition of mineral and royalty reserves primarily in East Texas, the Permian Basin, and the Williston Basin.

³Includes extensions and additions related to drilling activities within multiple basins.

⁴Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian Basin.

⁵As of December 31, 2018 and 2019, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries. As of December 31, 2017, proved developed reserves of 61 MBoe were attributable to noncontrolling interests.

⁶As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion.


	Year Ended December 31,
	2019		2018		2017
	(in thousands)
Future cash inflows	$	1,619,147	$	2,038,508	$	1,643,582
Future production costs	(177,550)		(222,342)		(211,064)
Future development costs	(54,132)		(58,403)		(70,111)
Future income tax expense	(5,244)		(6,333)		(2,655)
Future net cash flows (undiscounted)	1,382,221		1,751,430		1,359,752
Annual discount 10% for estimated timing	(534,327)		(663,814)		(497,103)
Total¹	$	847,894	$	1,087,616	$	862,649

¹Includes standardized measure of discounted future net cash flows of approximately $0.5 million for December 31, 2017 attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:


	Year Ended December 31,
	2019		2018		2017
	(in thousands)
Standardized measure, beginning of year	$	1,087,616	$	862,649	$	603,015
Sales, net of production costs	(384,745)		(475,742)		(295,941)
Net changes in prices and production costs related to future production	(229,651)		275,091		161,221
Extensions, discoveries and improved recovery, net of future production and development costs	186,424		370,695		166,616
Previously estimated development costs incurred during the period	—		14,509		11,118
Revisions of estimated future development costs	1,198		(558)		2,653
Revisions of previous quantity estimates, net of related costs	51,405		(5,401)		60,476
Accretion of discount	109,158		86,441		60,512
Purchases of reserves in place, less related costs	1,730		8,975		113,342
Changes in timing and other	24,759		(49,043)		(20,363)
Net increase (decrease) in standardized measures	(239,722)		224,967		259,634
Standardized measure, end of year	$	847,894	$	1,087,616	$	862,649

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Selected Quarterly Financial Information—Unaudited

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Information-Unaudited

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except for per unit data)
2019
Total revenue	$	83,806	$	163,618	$	137,369	$	103,028
Income (loss) from operations	14,594		100,666		75,233		44,679
Net income (loss)	9,017		95,087		70,247		40,017
Net income (loss) attributable to the general partner and common and subordinated units	3,767		89,837		64,997		34,767
Net income (loss) attributable to common and subordinated units per unit (basic)¹
Per common unit (basic)	$	0.02	$	0.45	$	0.32	$	0.17
Per subordinated unit (basic)	0.02		0.39		—		—
Net income (loss) attributable to common and subordinated units per unit (diluted)¹
Per common unit (diluted)	$	0.02	$	0.44	$	0.32	$	0.17
Per subordinated unit (diluted)	0.02		0.39		—		—
Cash distributions declared and paid per limited partner unit
Per common unit	$	0.3700	$	0.3700	$	0.3700	$	0.3700
Per subordinated unit	0.3700		0.3700		—		—
Total assets	$	1,711,887	$	1,724,555	$	1,595,813	$	1,545,208
Long-term debt	435,000		436,000		413,000		394,000
Total mezzanine equity	298,361		298,361		298,361		298,361
2018
Total revenue	$	114,494	$	109,309	$	139,718	$	246,047
Income (loss) from operations	47,960		33,524		66,180		170,717
Net income (loss)	41,957		28,690		60,775		164,138
Net income (loss) attributable to the general partner and common and subordinated units	36,655		23,488		55,503		158,865
Net income (loss) attributable to common and subordinated units per unit (basic)¹
Per common unit (basic)	$	0.23	$	0.17	$	0.27	$	0.78
Per subordinated unit (basic)	0.13		0.06		0.27		0.78
Net income (loss) attributable to common and subordinated units per unit (diluted)¹
Per common unit (diluted)	$	0.23	$	0.17	$	0.27	$	0.72
Per subordinated unit (diluted)	0.13		0.06		0.27		0.78
Cash distributions declared and paid per limited partner unit
Per common unit	$	0.3125	$	0.3125	$	0.3375	$	0.3700
Per subordinated unit	0.2088		0.2087		0.3375		0.3700
Total assets	$	1,635,978	$	1,669,464	$	1,754,259	$	1,750,124
Long-term debt	436,000		421,000		402,000		410,000
Total mezzanine equity	300,644		298,361		298,361		298,361

¹See Note 13 – Earnings Per Unit in the consolidated financial statements.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2019
Accounting Policies [Abstract]
Use of estimates	Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates. The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.
Cash and cash equivalents	Cash and Cash Equivalents The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts Receivable The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.
Commodity derivative financial instruments	Commodity Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within Gain (loss) on commodity derivative instruments.
Concentration of credit risk	Concentration of Credit Risk Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. The Partnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 7 – Significant Customers for further discussion.
Oil and natural gas properties	Oil and Natural Gas Properties The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. The costs of unproved leasehold and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which the Partnership also refers to as a depletable unit. As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Other property and equipment	Other Property and Equipment Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from 3 years to 7 years.
Repairs and maintenance	Repairs and Maintenance The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.
Debt issuance costs	Debt Issuance Costs Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated.
Asset retirement obligations	Asset Retirement Obligations Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.
Leases	Leases On January 1, 2019, the Partnership adopted ASC 842, Leases, using the modified retrospective method. ASC 842 requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Partnership used January 1, 2019, the beginning of the period of adoption, as its date of initial application. The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard. The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019. ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of December 31, 2019 and were not considered material to the Partnership. There was no related impact on the consolidated statement of operations. The standard had no impact on the Partnership’s debt covenant compliance under existing agreements. The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets. As of December 31, 2019, none of the Partnership’s leases were classified as financing leases. ROU assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments. The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Partnership will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.
Revenue recognition	Revenues from Contracts with Customers ASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018. Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership recognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Production imbalances The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. Allocation of transaction price to remaining performance obligations Oil and natural gas sales The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
Income taxes	Income Taxes The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxes are not material. Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.
Fair value of financial instruments	Fair Value of Financial Instruments The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31, 2019 and 2018 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurements for further discussion.
Incentive compensation	Incentive Compensation Incentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant date fair values. Liability awards are awards that are expected to be settled in cash or an unknown number of common units on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans. Incentive compensation expense is charged to General and administrative expense on the consolidated statements of operations. See Note 9 – Incentive Compensation for additional discussion.
Recent accounting pronouncements	Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the adoption of this update will have an impact on its financial position, results of operations, or liquidity.
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 units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Accounts Receivable

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


	December 31,
	2019		2018
	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	71,022	$	107,804
Other	7,192		5,344
Total accounts receivable	$	78,214	$	113,148

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following:


	December 31,
	2019		2018
	(in thousands)
Accrued liabilities:
Accrued capital expenditures	$	2,019	$	32,945
Accrued incentive compensation	9,057		16,109
Accrued property taxes	8,131		5,822
Accrued other	3,495		5,213
Total accrued liabilities	$	22,702	$	60,089

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation Liability

The following table describes changes to the Partnership’s ARO liability for the periods presented:


	For the year ended December 31,
	2019		2018
	(in thousands)
Beginning asset retirement obligations	$	15,475	$	14,509
Liabilities incurred	209		245
Liabilities settled	(1,073)		(129)
Accretion expense	1,117		1,103
Revisions in estimated costs	976		(16)
Dispositions	(620)		(237)
Ending asset retirement obligations	$	16,084	$	15,475
Current asset retirement obligations	$	431	$	527
Non-current asset retirement obligations	$	15,653	$	14,948

Oil and Natural Gas Properties Acquisitions (Tables)

12 Months Ended

Dec. 31, 2019

The following table summarizes these acquisitions:


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

	(in thousands)
February	$	173	$	8,437	$	1	$	8,611	$	8,611
March	24		—		—		24		24
June	527		3,268		—		3,795		3,795
Total fair value	$	724	$	11,705	$	1	$	12,430	$	12,430


	Assets Acquired		Consideration Paid
	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
Q4 2017	2,267		2,137		130
Total acquired	$	56,731	$	51,688	$	5,043

Noble Acquisition

Schedule of Pro Forma Information From Business Acquisition

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


	Assets Acquired
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid¹		Acquisition-Related Costs²
	(in thousands)
Noble Assets	$	68,877	$	256,542	$	5,917	$	331,336	$	331,336	$	247

¹ Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the year ended December 31, 2018.

² Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016.


	For the Year Ended December 31,
	2017		2016
	(in thousands, except per unit amounts)
Revenue and other income	$	468,103	$	288,772
Net income (loss)	$	178,970	$	33,264
Net income (loss) attributable to noncontrolling interests	34		12
Distributions on Series A redeemable preferred units	(3,117)		(5,763)
Distributions on Series B cumulative convertible preferred units	(21,000)		(21,000)
Net income (loss) attributable to the general partner and common and subordinated units	$	154,887	$	6,513
Allocation of net income (loss):
General partner interest	—		—
Common units	99,776		20,696
Subordinated units	55,111		(14,183)
	$	154,887	$	6,513
Net income (loss) attributable to limited partners per common and subordinated unit:
Per common unit (basic)	$	1.02	$	0.22
Per subordinated unit (basic)	$	0.58	$	(0.15)
Per common unit (diluted)	$	1.02	$	0.22
Per subordinated unit (diluted)	$	0.58	$	(0.15)

2018 Acquisitions

The following table summarizes these acquisitions:


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

	(in thousands)
March	$	984	$	21,452	$	133	$	22,569	$	22,569	$	—
June	883		13,688		8		14,579		14,579		—
July	4,349		7,944		215		12,508		3,764		8,744
August	5,000		34,673		74		39,747		26,461		13,286
September	1,176		—		—		1,176		1,176		—
November	1,166		—		—		1,166		1,166		—
Total fair value	$	13,558	$	77,757	$	430	$	91,745	$	69,715	$	22,030

2017 Acquisitions

Derivative Instruments and Hedging Activities Disclosure [Abstract]

The following table summarizes these acquisitions:


	Assets Acquired														Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash		Fair Value of Common Units Issued		Acquisition-Related Costs¹
	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	27,380	$	12,026	$	1,162
June	5,006		45,477		—		50,483		4,802		45,681		1,481
August	3,277		9,984		—		13,261		4,289		8,972		107
September	3,120		—		—		3,120		3,120		—		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	39,591	$	66,679	$	2,750

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

Commodity Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2019

Summary of Fair Value and Classification of Derivative Instruments


		As of December 31, 2019
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	$	19,028	$	(4,238)	$	14,790
Long-term asset	Deferred charges and other long-term assets	713		(105)		608
Total assets		$	19,741	$	(4,343)	$	15,398
Liabilities:
Current liability	Commodity derivative liabilities	$	4,397	$	(4,238)	$	159
Long-term liability	Commodity derivative liabilities	123		(105)		18
Total liabilities		$	4,520	$	(4,343)	$	177


		As of December 31, 2018
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	38,746	$	(776)	$	37,970
Long-term asset	Deferred charges and other long-term assets	11,518		(1,450)		10,068
Total assets		$	50,264	$	(2,226)	$	48,038
Liabilities:
Current liability	Commodity derivative liabilities	$	776	$	(776)	$	—
Long-term liability	Commodity derivative liabilities	1,450		(1,450)		—
Total liabilities		$	2,226	$	(2,226)	$	—

Changes in Fair Value of Company's Commodity Derivative Instruments


	For the year ended December 31,
Derivatives not designated as hedging instruments	2019		2018		2017
	(in thousands)
Beginning fair value of commodity derivative instruments	$	48,038	$	(5,028)	$	(16,719)
Gain (loss) on oil derivative instruments	(34,728)		24,300		(5,091)
Gain (loss) on natural gas derivative instruments	29,773		(9,469)		31,993
Net cash paid (received) on settlements of oil derivative instruments	(8,536)		34,905		(10,901)
Net cash paid (received) on settlements of natural gas derivative instruments	(19,326)		3,330		(4,310)
Net change in fair value of commodity derivative instruments	(32,817)		53,066		11,691
Ending fair value of commodity derivative instruments	$	15,221	$	48,038	$	(5,028)

Summary of Open Derivative Contracts

The Partnership had the following open derivative contracts for oil as of December 31, 2019:


	Volume (Bbl)	Weighted Average Price (per Bbl)		Range (per Bbl)
Period and Type of Contract						Low		High
Oil Swap Contracts:
2019
Fourth quarter	312,000	$	58.50	$	52.82	$	63.75
2020
First quarter	630,000	$	57.32	$	54.92	$	58.65
Second quarter	630,000	57.32		54.92		58.65
Third quarter	630,000	57.32		54.92		58.65
Fourth quarter	630,000	57.32		54.92		58.65


	Volume (Bbl)	Weighted Average Floor Price (Per Bbl)		Weighted Average Ceiling Price (Per Bbl)
Period and Type of Contract
Oil Collar Contracts:
2019
Fourth quarter	20,000	$	65.00	$	74.00
2020
First quarter	210,000	$	56.43	$	67.14
Second quarter	210,000	56.43		67.14
Third quarter	210,000	56.43		67.14
Fourth quarter	210,000	56.43		67.14

The Partnership had the following open derivative contracts for natural gas as of December 31, 2019:


	Volume (MMBtu)	Weighted Average Price (per MMBtu)		Range (per MMBtu)
Period and Type of Contract						Low		High
Natural Gas Swap Contracts:
2020
First quarter	10,010,000	$	2.69	$	2.55	$	2.74
Second quarter	10,010,000	2.69		2.55		2.74
Third quarter	10,120,000	2.69		2.55		2.74
Fourth quarter	10,120,000	2.69		2.55		2.74

- 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.

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+ Details

Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2019

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
	Level 1		Level 2		Level 3		Netting		Total
	(In thousands)
As of December 31, 2019
Financial Assets
Commodity derivative instruments	$	—	$	19,741	$	—	$	(4,343)	$	15,398
Financial Liabilities
Commodity derivative instruments	—		4,520		—		(4,343)		177
As of December 31, 2018
Financial Assets
Commodity derivative instruments	$	—	$	50,264	$	—	$	(2,226)	$	48,038
Financial Liabilities
Commodity derivative instruments	—		2,226		—		(2,226)		—

Incentive Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Summary of Information about Restricted Units

The following table summarizes information about restricted units for the year ended December 31, 2019.


	Number of Units	Weighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2018	1,334,016	$	17.29
Granted	496,316	17.09
Vested	(778,956)	16.64
Converted	—	—
Forfeited	(13,117)	17.49
Unvested at December 31, 2019	1,038,259	17.67

Summary of Information about Performance Units

The following table summarizes information about performance units for the year ended December 31, 2019.


Performance units	Number of Units	Weighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2018	1,811,810	$	15.94
Granted¹	953,638	16.84
Vested	(1,378,188)	14.83
Forfeited	(18,178)	17.63
Unvested at December 31, 2019	1,369,082	17.66

¹ Includes 457,322 of additional performance units issued based on the final performance multiplier for awards that vested in the period.

Summary of Incentive Compensation Expense


	Year Ended December 31,
Incentive compensation expense	2019		2018		2017
	(In thousands)
Cash — short and long-term incentive plan	$	5,593	$	9,301	$	4,373
Equity-based compensation — restricted common and subordinated units	10,751		13,624		13,476
Equity-based compensation — restricted performance units	7,386		14,188		17,367
Board of Directors incentive plan	2,347		2,322		2,202
Total incentive compensation expense	$	26,077	$	39,435	$	37,418

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2019

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 unit:


	For the Year Ended December 31,
	2019		2018		2017
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	214,368	$	295,560	$	157,153
Net (income) loss attributable to noncontrolling interests	—		(24)		34
Distributions on Series A redeemable preferred units	—		(25)		(3,117)
Distributions on Series B cumulative convertible preferred units	(21,000)		(21,000)		(1,925)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	193,368	$	274,511	$	152,145
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—	$	—	$	—
Common units	169,375		154,662		98,389
Subordinated units	23,993		119,849		53,756
	$	193,368	$	274,511	$	152,145
Weighted average common units outstanding:
Weighted average common units outstanding (basic)	168,230		106,064		97,400
Effect of dilutive securities	146		15,200		—
Weighted average common units outstanding (diluted)	168,376		121,264		97,400
Weighted average subordinated units outstanding:
Weighted average subordinated units outstanding (basic)	37,740		96,099		95,149
Effect of dilutive securities	—		247		—
Weighted average subordinated units outstanding (diluted)	37,740		96,346		95,149
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	1.01	$	1.46	$	1.01
Per subordinated unit (basic)	0.64		1.25		0.56
Per common unit (diluted)¹	1.01		1.45		1.01
Per subordinated unit (diluted)²	0.64		1.25		0.56

¹For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $21.0 million.

²For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $0.3 million.

The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:


	For the Year Ended December 31,
	2019	2018	2017
	(in thousands)
Potentially dilutive securities (common units):
Series A redeemable preferred units on an as-converted basis	—	189	996
Series B cumulative convertible preferred units on an as-converted basis	14,968	—	1,612
	14,968	189	2,608

Potentially dilutive securities (subordinated units):
Series A redeemable preferred units on an as-converted basis	—	—	1,304

Common and Subordinated Units (Tables)

12 Months Ended

Dec. 31, 2019