Supplemental Oil and Natural Gas Disclosure (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Cost Incurred in Oil and Gas Property Acquisition, 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,
	2017		2016		2015
	(in thousands)
Acquisition Costs of Properties:1
Proved	$	96,596	$	40,242	$	2,302
Unproved	383,535		100,888		60,994
Exploration Costs	618		645		2,592
Development Costs	81,056		73,316		60,056
Total	$	561,805	$	215,091	$	125,944

^1.  See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

Capitalized Costs Relating to Oil and Gas Producing Activities

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,
	2017			2016
	(in thousands)
Proved properties	$	2,258,893		$	2,091,337
Unproved properties	988,720			605,736
Total	3,247,613			2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,766,842		)	(1,652,930		)
Oil and natural gas properties, net	$	1,480,771		$	1,044,143

Schedule of Oil and Gas In Process Activities

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, 2014	17,067		204,256		51,109
Revisions of previous estimates1	(197	)	(17,043	)	(3,037	)
Purchases of minerals in place2	8		367		69
Extensions, discoveries and other additions3	2,529		57,484		12,110
Production	(3,565	)	(41,389	)	(10,463	)
Net proved reserves at December 31, 2015	15,842		203,675		49,788
Revisions of previous estimates1	3,007		29,024		7,844
Purchases of minerals in place4	1,322		5,683		2,269
Extensions, discoveries and other additions5	1,877		79,455		15,120
Production	(3,680	)	(47,498	)	(11,596	)
Net proved reserves at December 31, 2016	18,368		270,339		63,425
Revisions of previous estimates1	(1,234	)	21,067		2,277
Purchases of minerals in place6	2,267		30,250		7,309
Extensions, discoveries and other additions7	2,050		38,397		8,449
Production	(3,552	)	(59,779	)	(13,515	)
Net proved reserves at December 31, 2017	17,899		300,274		67,945
Net Proved Developed Reserves8
December 31, 2015	15,497		174,555		44,590
December 31, 2016	18,150		223,057		55,327
December 31, 2017	17,891		233,017		56,727
Net Proved Undeveloped Reserves9
December 31, 2015	345		29,120		5,198
December 31, 2016	218		47,282		8,098
December 31, 2017	8		67,257		11,218

¹   Revisions 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.

²   Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.

³   Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.

⁴   Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.

⁵ Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays.

⁶   Includes the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins.

⁷   Includes extensions and additions related to drilling activities within multiple basins.

⁸ Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.

⁹ As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves

	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Future cash inflows	$	1,643,582		$	1,267,179		$	1,211,290
Future production costs	(211,064		)	(193,749		)	(205,861		)
Future development costs	(70,111		)	(36,509		)	(84,746		)
Future income tax expense	(2,655		)	(3,516		)	—
Future net cash flows (undiscounted)	1,359,752			1,033,405			920,683
Annual discount 10% for estimated timing	(497,103		)	(430,390		)	(365,711		)
Total1	$	862,649		$	603,015		$	554,972

¹   Includes standardized measure of discounted future net cash flows of approximately $0.5 million, $0.6 million, and $0.7 million for December 31, 2017, 2016, and 2015, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

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

	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Standardized measure, beginning of year	$	603,015		$	554,972		$	1,143,094
Sales, net of production costs	(295,941		)	(210,354		)	(222,206		)
Net changes in prices and production costs related to future production	169,608			(81,456		)	(621,065		)
Extensions, discoveries and improved recovery, net of future production and development costs	113,199			86,606			165,020
Previously estimated development costs incurred during the period	11,118			28,909			7,084
Revisions of estimated future development costs	2,653			—			669
Revisions of previous quantity estimates, net of related costs	86,228			147,507			(67,911		)
Accretion of discount	60,512			55,662			114,309
Purchases of reserves in place, less related costs	107,891			34,751			584
Other	4,366			(13,582		)	35,394
Net increase (decrease) in standardized measures	259,634			48,043			(588,122		)
Standardized measure, end of year	$	862,649		$	603,015		$	554,972