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, 2015, 2014 and 2013, 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 2015, 2014 and 2013. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:


	2015		2014		2013
Oil (per Bbl)	$	50.16	$	94.56	$	97.28
Natural gas liquids (per Bbl)	$	15.13	$	31.50	$	30.16
Gas (per Mcf)	$	2.64	$	4.55	$	3.66

Oil, NGL 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, 2015, 2014 and 2013, 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 — December 31, 2012		37,252			29,100			174,760			95,479
Extensions and discoveries		14,252			6,531			38,993			27,282
Purchases of minerals in place		62			14			197			109
Production(1)		(1,444	)		(951	)		(6,737	)		(3,517	)
Revisions to previous estimates		(4,055	)		(2,102	)		8,789			(4,692	)


Balance — December 31, 2013		46,067			32,593			216,002			114,661
Extensions and discoveries		19,347			10,658			79,454			43,247
Production(1)		(2,024	)		(1,461	)		(10,773	)		(5,281	)
Revisions to previous estimates		(8,052	)		(883	)		15,337			(6,379	)


Balance — December 31, 2014		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

(1)	Production includes 560 MMcf, 1,390 MMcf and 1,530 MMcf related to field fuel in 2013, 2014 and 2015, respectively.


Total Proved Reserves	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved Developed Reserves:
January 1, 2013		8,816		11,761		73,178		32,774
December 31, 2013		13,646		14,919		99,742		45,189
January 1, 2014		13,646		14,919		99,742		45,189
December 31, 2014		17,978		19,082		138,961		60,220
January 1, 2015		17,978		19,082		138,961		60,220
December 31, 2015		15,667		20,414		154,652		61,856

Proved Undeveloped Reserves:
January 1, 2013		28,436		17,339		101,582		62,705
December 31, 2013		32,421		17,674		116,260		69,472
January 1, 2014		32,421		17,674		116,260		69,472
December 31, 2014		37,360		21,825		161,059		86,028
January 1, 2015		37,360		21,825		161,059		86,028
December 31, 2015		38,829		29,072		221,335		104,790

The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2015, 2014 and 2013:

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 recorded net downward revisions totaling 8.7 MMBoe, including the reclassification of 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 also included 13 MMBoe of positive revisions resulting from cost reductions, updated well performance and technical parameters, offset by 9.8 MMBoe of negative revisions 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.

Year Ended December 31, 2014

Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we recorded downward revisions totaling 6.4 MMBoe, including the reclassification of 9.3 MMBoe of proved undeveloped reserves to probable undeveloped. The reserves reclassified from proved undeveloped to probable undeveloped included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions also included 6.3 MMBoe of positive net revisions attributable to updated well performance and 0.7 MMBoe of positive revisions due to pricing, offset by 4.1 MMBoe of negative revisions resulting from updated technical parameters and costs. We produced 5.3 MMBoe during 2014. This production included 1,390 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, 2013

Extensions and discoveries for 2013 were 27.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. We produced 3.5 MMBoe during 2013. This production included 560 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lifts) before the gas was delivered to a sales point. During 2013, we recorded downward revisions totaling 4.7 MMBoe. Revisions included the reclassification of 7.8 MMBoe of proved undeveloped reserves to probable undeveloped, partially offset by 3.1 MMBoe of positive revisions attributable to gas that will be produced and utilized as field fuel. The reserves reclassified from proved undeveloped to probable undeveloped were attributable to vertical Canyon locations in Project Pangea. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper locations beyond five years from initial booking was necessary to integrate their development with the shallower Clearfork and Wolfcamp target zones.

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, 2015, 2014 and 2013 (in thousands):


	Years Ended December 31,
	2015			2014			2013
Future cash flows	$	4,097,568		$	7,430,368		$	5,953,060
Future production costs		(1,237,888	)		(1,704,333	)		(1,372,005	)
Future development costs		(934,814	)		(1,247,446	)		(1,154,685	)
Future income tax expense		(307,374	)		(1,267,025	)		(919,454	)

Future net cash flows		1,617,492			3,211,564			2,506,916
10% annual discount for estimated timing of cash flows		(1,157,097	)		(2,155,749	)		(1,830,639	)

Standardized measure of discounted future net cash flows	$	460,395		$	1,055,815		$	676,277

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,
	2015			2014			2013
Balance, beginning of period	$	1,055,815		$	676,277		$	494,220
Net change in sales and transfer prices and in production (lifting) costs related to future production		(1,405,864	)		(59,920	)		74,088
Changes in estimated future development costs		231,900			(388,772	)		(301,132	)
Sales and transfers of oil and gas produced during the period		(91,278	)		(209,893	)		(149,310	)
Net change due to extensions, discoveries and improved recovery		156,783			534,231			360,080
Net change due to purchase of minerals in place		—			—			1,435
Net change due to revisions in quantity estimates		(59,305	)		(78,801	)		(61,931	)
Previously estimated development costs incurred during the period		146,237			382,995			287,898
Accretion of discount		105,582			113,188			87,937
Other		6,915			(11,897	)		1,896
Net change in income taxes		313,610			98,407			(118,904	)

Standardized Measure of discounted future net cash flows	$	460,395		$	1,055,815		$	676,277