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

¹ See 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

¹ Proved 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 estimates 1	(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

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 in East Texas, the Permian Basin, and the Williston Basin.

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

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

⁵ As 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.

⁶ As 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

¹ Includes 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.