

	December 31,
	2019			2018
	(in thousands)
Oil and natural gas properties:
Proved properties	$	8,799,840		$	6,659,444
Unproved properties	2,472,284			3,288,802
Total oil and natural gas properties	11,272,124			9,948,246
Less accumulated depreciation, depletion and amortization	(2,117,963		)	(1,295,098		)
Net oil and natural gas properties capitalized	$	9,154,161		$	8,653,148



	Year Ended December 31,
	2019		2018		2017
	(in thousands)
Acquisition costs:
Proved properties	$	24,855	$	17,310	$	482,160
Unproved properties	27,165		119,662		2,893,434
Development costs	1,372,919		1,762,218		1,207,401
Total	$	1,424,939	$	1,899,190	$	4,582,995

The following table sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of the Company’s oil, natural gas and NGLs operations.



	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Oil, natural gas and natural gas liquid sales⁽¹⁾	$	1,949,977		$	1,814,747		$	961,994
Lease operating expenses	(177,148		)	(144,292		)	(102,169		)
Transportation and processing costs⁽¹⁾	(41,198		)	(32,573		)	—
Production and ad valorem taxes	(124,961		)	(108,342		)	(59,641		)
Depreciation, depletion and amortization	(775,849		)	(569,691		)	(340,778		)
Accretion of asset retirement obligations	(1,465		)	(1,422		)	(971		)
Total	$	829,356		$	958,427		$	458,435




(1)	Natural gas and NGLs sales and transportation and processing costs for the years ended December 31, 2019 and 2018 reflect adjustments associated with Parsley’s adoption of ASC 606, effective January 1, 2018.

The following information represents estimates of the Company’s proved reserves as of December 31, 2019, which have been prepared and presented in accordance with SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2019 was based on an unweighted average 12-month average U.S. Energy Information Administration WTI posted price per Bbl for oil and NGLs and a Waha spot natural gas price per Mcf for natural gas, adjusted for transportation, quality and basis differentials, as set forth in the following table:

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table and subsequent narrative disclosure provides a roll forward of the total proved reserves for the years ended December 31, 2019, 2018 and 2017, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:



	Year Ended December 31, 2019
	Crude Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total MBoe
Proved Developed and Undeveloped Reserves:
Beginning of the year	294,446		572,038		131,933		521,719
Extensions and discoveries	84,186		132,642		32,457		138,750
Revisions of previous estimates	(19,269	)	60,128		(5,043	)	(14,291	)
Purchases of reserves in place	354		556		107		554
Divestures of reserves in place	(1,590	)	(4,189	)	(788	)	(3,076	)
Production	(31,664	)	(51,933	)	(11,002	)	(51,322	)
End of the year	326,463		709,242		147,664		592,334

Proved Developed Reserves:
Beginning of the year	170,526		358,733		81,000		311,315
End of the year	206,849		472,160		96,202		381,744

Proved Undeveloped Reserves:
Beginning of the year	123,920		213,305		50,933		210,404
End of the year	119,614		237,082		51,462		210,590



	Year Ended December 31, 2018
	Crude Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total MBoe
Proved Developed and Undeveloped Reserves:
Beginning of the year	248,531		451,703		92,632		416,447
Extensions and discoveries	102,274		130,692		35,722		159,778
Revisions of previous estimates	(22,047	)	48,992		16,164		2,283
Purchases of reserves in place	3,379		5,963		1,240		5,613
Divestures of reserves in place	(12,335	)	(27,947	)	(5,472	)	(22,465	)
Production	(25,356	)	(37,365	)	(8,353	)	(39,937	)
End of the year	294,446		572,038		131,933		521,719

Proved Developed Reserves:
Beginning of the year	119,591		240,337		49,751		209,399
End of the year	170,526		358,733		81,000		311,315

Proved Undeveloped Reserves:
Beginning of the year	128,940		211,366		42,881		207,048
End of the year	123,920		213,305		50,933		210,404



	Year Ended December 31, 2017
	Crude Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total MBoe
Proved Developed and Undeveloped Reserves:
Beginning of the year	136,536		223,605		48,543		222,347
Extensions and discoveries	99,916		161,989		33,426		160,340
Revisions of previous estimates	(709	)	32,342		4,522		9,205
Purchases of reserves in place	33,017		64,055		12,121		55,814
Divestures of reserves in place	(3,839	)	(6,962	)	(1,468	)	(6,467	)
Production	(16,390	)	(23,326	)	(4,512	)	(24,792	)
End of the year	248,531		451,703		92,632		416,447

Proved Developed Reserves:
Beginning of the year	61,133		123,946		24,306		106,097
End of the year	119,591		240,337		49,751		209,399

Proved Undeveloped Reserves:
Beginning of the year	75,403		99,659		24,237		116,250
End of the year	128,940		211,366		42,881		207,048

Extensions and Discoveries. For the years ended December 31, 2019, 2018 and 2017, extensions and discoveries contributed to the increase of 138,750 MBoe, 159,778 MBoe and 160,340 MBoe in the Company’s proved reserves, respectively, and for each such year the increase is attributable to the Company’s horizontal drilling program in the Midland Basin and the Delaware Basin.

Negative revisions of previous estimates for 2019 were 14,291 MBoe. The main driver of these revisions was the reclassification of certain proved undeveloped (“PUD”) reserves to unproved reserves, which resulted in a 23,686 MBoe downward revision to previous estimates related to the removal of reserves for PUD locations determined to be outside of the Company’s five-year capital expenditure plan. Other drivers included changes in well performance, working interest and operating expenses, which together resulted in a positive revision of 11,498 MBoe. A negative revision of 2,103 MBoe was attributable to a price adjustment due to a decrease in pricing as calculated using SEC guidelines.

Positive revisions of previous estimates for 2018 were 2,283 MBoe. The main driver of these positive revisions was the adoption of ASC 606, which resulted in a positive revision of 11,434 MBoe. Other drivers included changes in well performance, working interest, operating expenses and pricing, which together resulted in a positive revision of 3,063 MBoe. The main driver of these downward revisions was the reclassification of certain PUD reserves to unproved reserves, which accounted for a 12,214 MBoe downward revision to previous estimates related to the removal of reserves for locations determined to be outside of the Company’s five-year capital expenditure plan.

Positive revisions of previous estimates for 2017 were 9,205 MBoe. The main driver of these adjustments was better than expected performance for a total of 8,134 MBoe. Additionally, positive revisions of 2,752 MBoe and 3,044 MBoe were recorded due to increases in oil prices and production, respectively, as compared to the year ended December 31, 2016. These were offset by negative revisions of 4,725 MBoe associated with the reclassification of PUD reserves to unproved reserves.

Purchases of Reserves in Place. For the years ended December 31, 2019, 2018 and 2017, the Company added 554 MBoe, 5,613 MBoe and 55,814 MBoe of reserves, respectively, primarily as a result of the acquisition of developed and undeveloped acreage in the Midland and Delaware Basins. For the year ended December 31, 2019, the Company acquired 554 MBoe of proved reserves in the Midland Basin. For the year ended December 31, 2018, the Company acquired 5,550 MBoe of proved reserves in the Midland Basin and 63 MBoe of proved reserves in the Delaware Basin. For the year ended December 31,

Divestitures of Reserves in Place. As a result of divestitures of developed and undeveloped acreage in the Midland and Delaware Basins, the Company’s reserves decreased by 3,076 MBoe, 22,465 MBoe and 6,467 MBoe during the years ended December 31, 2019, 2018 and 2017, respectively. For the year ended December 31, 2019, the Company divested 3,076 MBoe of proved reserves in the Midland Basin. For the year ended December 31, 2018, the Company divested 22,372 MBoe of proved reserves in the Midland Basin and 93 MBoe of proved reserves in the Delaware Basin. For the year ended December 31, 2017, the Company divested 5,936 MBoe of proved reserves in the Midland Basin and 531 MBoe of proved reserves in the Delaware Basin.

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of a property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2019, 2018 and 2017 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.



	December 31,
	2019			2018			2017
	(in thousands)
Future cash inflows	$	20,409,082		$	22,861,246		$	15,421,590
Future development costs	(2,280,552		)	(2,459,587		)	(2,181,447		)
Future production costs	(6,240,997		)	(5,944,022		)	(4,536,530		)
Future income tax expenses	(1,485,523		)	(2,061,409		)	(1,102,385		)
Future net cash flows	10,402,010			12,396,228			7,601,228
10% discount to reflect timing of cash flows	(5,439,514		)	(6,502,326		)	(4,215,321		)
Standardized measure of discounted future net cash flows	$	4,962,496		$	5,893,902		$	3,385,907

In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2019, 2018 and 2017 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.



	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the year	$	5,893,902		$	3,385,907		$	1,304,091
Sales of oil and natural gas, net of production costs	(1,606,669		)	(1,561,190		)	(800,553		)
Purchase of minerals in place	7,411			76,478			489,910
Divestiture of minerals in place	(19,768		)	(167,412		)	(50,257		)
Extensions and discoveries, net of future development costs	1,714,706			3,016,035			1,864,041
Previously estimated development costs incurred during the period	469,798			290,108			58,377
Net changes in prices and production costs	(2,205,679		)	1,065,693			525,693
Changes in estimated future development costs	83,125			(177,118		)	(150,028		)
Revisions of previous quantity estimates	(146,203		)	161,860			142,510
Accretion of discount	677,486			391,803			148,314
Net change in income taxes	187,697			(348,834		)	(353,073		)
Net changes in timing of production and other	(93,310		)	(239,428		)	206,882
Standardized measure of discounted future net cash flows at the end of the year	$	4,962,496		$	5,893,902		$	3,385,907