Supplemental Oil and Natural Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2021

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,
	2021		2020		2019
	(in thousands)
Acquisition Costs of Properties1:
Proved	$	4,965	$	—	$	2,288
Unproved	15,559		28		41,643
Exploration Costs	1,049		—		3
Development Costs1	3,964		2,742		34,617
Total	$	25,537	$	2,770	$	78,551

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.

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,
	2021		2020
	(in thousands)
Proved properties1	$	2,064,232	$	2,220,354
Unproved properties	937,395		937,464
Total	3,001,627		3,157,818
Accumulated depreciation, depletion, amortization, and impairment	(1,869,731)		(1,987,332)
Oil and natural gas properties, net	$	1,131,896	$	1,170,486

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

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. 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. For estimates of oil reserves, the average WTI spot oil prices used were $66.55, $39.54, and $55.85 per barrel as of December 31, 2021, 2020, and 2019, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $3.60, $1.99, and $2.58 per MMBTU as of December 31, 2021, 2020, and 2019, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties were $63.17 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2021, $36.43 per barrel for oil and $1.60 per Mcf for natural gas as of December 31, 2020, and $52.15 per barrel for oil and $2.36 per Mcf for natural gas as of December 31, 2019.

	Crude Oil (MBbl)	Natural Gas (MMcf)	Total (MBoe)
Net proved reserves at December 31, 2018	17,567	314,020	69,904
Revisions of previous estimates 1	951	19,136	4,140
Purchases of minerals in place2	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
Revisions of previous estimates1	2,490	(22,337)	(1,233)
Sales of minerals in place4	(1,262)	(3,132)	(1,784)
Extensions, discoveries and other additions3	1,569	24,667	5,680
Production	(3,895)	(67,945)	(15,219)
Net proved reserves at December 31, 2020	15,952	240,211	55,987
Revisions of previous estimates1	4,817	38,537	11,240
Purchases of minerals in place2	272	216	308
Sales of minerals in place4	(135)	(6,194)	(1,167)
Extensions, discoveries and other additions3	1,911	32,592	7,343
Production	(3,646)	(61,445)	(13,887)
Net proved reserves at December 31, 2021	19,171	243,917	59,824
Net Proved Developed Reserves
December 31, 2019	17,050	263,371	60,945
December 31, 2020	15,952	230,411	54,354
December 31, 2021	19,111	224,222	56,481
Net Proved Undeveloped Reserves
December 31, 2019	—	45,587	7,598
December 31, 2020	—	9,800	1,633
December 31, 2021	60	19,695	3,343

1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable revisions in 2019 are related to well performance in certain Haynesville/ Bossier wells. The most notable revisions in 2020 are related to a reduction of royalty on certain Haynesville/Bossier wells in order to incentivize the operator to complete and turn the wells to sales. The most notable revisions in 2021 are related to changes in commodity pricing.

2 Includes the acquisition of mineral and royalty reserves. In 2020 these were primarily in East Texas and the Permian Basin and in 2021 these were primarily in the Permian Basin.

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

4 Includes divestitures of mineral and royalty reserves. In 2020 these were primarily in the Permian Basin and in 2021 these were primarily in the Anadarko Basin.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Future cash inflows	$	2,033,256	$	965,007	$	1,619,147
Future production costs	(206,785)		(99,124)		(177,550)
Future development costs	(43,500)		(59,692)		(54,132)
Future income tax expense	(6,322)		(3,019)		(5,244)
Future net cash flows (undiscounted)	1,776,649		803,172		1,382,221
Annual discount 10% for estimated timing	(804,527)		(309,675)		(534,327)
Total	$	972,122	$	493,497	$	847,894

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,
	2021		2020		2019
	(in thousands)
Standardized measure, beginning of year	$	493,497	$	847,894	$	1,087,616
Sales, net of production costs	(428,577)		(230,062)		(384,745)
Net changes in prices and production costs related to future production	537,659		(242,634)		(229,651)
Extensions, discoveries and improved recovery, net of future production and development costs	148,732		65,903		186,424
Previously estimated development costs incurred during the period	245		—		—
Revisions of estimated future development costs	2,254		(1,530)		1,198
Revisions of previous quantity estimates, net of related costs	210,039		(24,195)		51,405
Accretion of discount	49,530		85,109		109,158
Purchases of reserves in place, less related costs	9,254		—		1,730
Sales of reserves in place1	(1,037)		(26,795)		(3,323)
Changes in timing and other	(49,474)		19,807		28,082
Net increase (decrease) in standardized measures	478,625		(354,397)		(239,722)
Standardized measure, end of year	$	972,122	$	493,497	$	847,894