10.	Disclosures About Oil and Gas Producing Activities (unaudited)

Proved Reserves

All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2017, 2016 and 2015, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.

The following table summarizes the prices used in the reserve estimates for 2017, 2016 and 2015. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:

	2017		2016		2015
Oil (per Bbl)	$	51.34	$	42.69	$	50.16
Natural gas liquids (per Bbl)	$	18.67	$	14.12	$	15.13
Gas (per Mcf)	$	2.99	$	2.47	$	2.64

Oil, NGLs and natural gas reserve 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 provides a summary of the changes of the total proved reserves for the years ended December 31, 2017, 2016 and 2015, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.

Total Proved Reserves	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance — January 1, 2015		55,338			40,907			300,020			146,248
Extensions and discoveries		11,054			10,630			79,268			34,895
Production(1)		(1,882	)		(1,694	)		(13,262	)		(5,787	)
Revisions to previous estimates		(10,014	)		(357	)		9,962			(8,710	)

Balance — December 31, 2015		54,496			49,486			375,988			166,646
Extensions and discoveries		6,529			4,564			33,347			16,651
Production(1)		(1,275	)		(1,529	)		(11,734	)		(4,759	)
Revisions to previous estimates		(9,719	)		(4,887	)		(45,324	)		(22,161	)

Balance — December 31, 2016		50,031			47,634			352,277			156,377
Extensions and discoveries		10,546			9,975			76,710			33,307
Acquisition of minerals in place		710			394			2,808			1,572
Production(1)		(1,107	)		(1,486	)		(11,148	)		(4,452	)
Revisions to previous estimates		(10,120	)		1,431			20,581			(5,259	)

Balance — December 31, 2017		50,060			57,948			441,228			181,545

(1)	Production included 1,530 MMcf, 1,330 MMcf and 1,319 MMcf related to field fuel in 2015, 2016 and 2017, respectively.

Total Proved Reserves	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved Developed Reserves:
January 1, 2015		17,978		19,082		138,961		60,220
December 31, 2015		15,667		20,414		154,652		61,856
December 31, 2016		13,466		20,375		150,208		58,875
December 31, 2017		13,853		23,180		176,201		66,399

Proved Undeveloped Reserves:
January 1, 2015		37,360		21,825		161,059		86,028
December 31, 2015		38,829		29,072		221,335		104,790
December 31, 2016		36,565		27,259		202,069		97,502
December 31, 2017		36,207		34,768		265,028		115,146

The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2017, 2016 and 2015:

Year Ended December 31, 2017

Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the Bolt-On Acquisition, and we reclassified 17.7 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 9.4 MMBoe resulting from updated well performance and technical parameters and an increase of 3.1 MMBoe due to higher commodity prices We produced 4.5 MMBoe during 2017. This production included 1,319 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2016

Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2015

Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices. We produced 5.8 MMBoe during 2015. This production included 1,530 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows at December 31, 2017, 2016 and 2015 (in thousands):

	Years Ended December 31,
	2017			2016			2015
Future cash flows	$	4,451,665		$	3,319,551		$	4,097,568
Future production costs		(1,279,777	)		(1,054,211	)		(1,237,888	)
Future development costs		(982,284	)		(829,926	)		(934,814	)
Future income tax expense		(323,308	)		(132,834	)		(307,374	)
Future net cash flows		1,866,296			1,302,580			1,617,492
10% annual discount for estimated timing of cash flows		(1,405,265	)		(1,004,825	)		(1,157,097	)
Standardized measure of discounted future net cash flows	$	461,031		$	297,755		$	460,395

Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

	Years Ended December 31,
	2017			2016			2015
Balance, beginning of period	$	297,755		$	460,395		$	1,055,815
Net change in sales and transfer prices and in production (lifting) costs related to future production		229,139			(191,841	)		(1,405,864	)
Changes in estimated future development costs		(72,439	)		17,405			231,900
Sales and transfers of oil and gas produced during the period		(78,803	)		(62,835	)		(91,278	)
Net change due to acquisition of minerals in place		17,331			—			—
Net change due to extensions, discoveries and improved recovery		49,377			13,988			156,783
Net change due to revisions in quantity estimates		(3,817	)		(25,236	)		(59,305	)
Previously estimated development costs incurred during the period		43,202			15,884			146,237
Accretion of discount		30,789			46,040			105,582
Other		(1,677	)		(9,500	)		6,915
Net change in income taxes		(49,826	)		33,455			313,610
Standardized Measure of discounted future net cash flows	$	461,031		$	297,755		$	460,395