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, 2012, 2011 and 2010, 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 2012, 2011 and 2010. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:


	2012		2011		2010
Oil (per Bbl)	$	90.21	$	89.65	$	74.90
Natural gas liquids (per Bbl)	$	37.88	$	49.63	$	39.25
Gas (per Mcf)	$	2.62	$	3.97	$	4.13

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, 2012, 2011 and 2010, 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, 2009		4,338			4,094			168,334			36,488
Extensions and discoveries		984			1,395			8,365			3,773
Purchases of minerals in place		383			786			4,736			1,958
Production		(247	)		(261	)		(6,290	)		(1,556	)
Revisions to previous estimates		(507	)		14,685			(24,756	)		10,052


Balance — December 31, 2010		4,951			20,699			150,389			50,715
Extensions and discoveries		11,847			7,010			40,146			25,548
Purchases of minerals in place		2,200			4,284			24,083			10,498
Production		(482	)		(798	)		(6,345	)		(2,338	)
Revisions to previous estimates		(465	)		(2,072	)		(29,466	)		(7,448	)


Balance — December 31, 2011		18,051			29,123			178,807			76,975
Extensions and discoveries		21,993			8,639			49,372			38,861
Production		(969	)		(904	)		(6,089	)		(2,888	)
Revisions to previous estimates		(1,823	)		(7,758	)		(47,330	)		(17,469	)


Balance — December 31, 2012		37,252			29,100			174,760			95,479


Proved Developed Reserves:
January 1, 2010		1,239			1,879			74,804			15,585
December 31, 2010		2,146			11,193			74,739			25,795
January 1, 2011		2,146			11,193			74,739			25,795
December 31, 2011		5,542			13,945			84,743			33,611
January 1, 2012		5,542			13,945			84,743			33,611
December 31, 2012		8,816			11,761			73,178			32,774

Proved Undeveloped Reserves:
January 1, 2010		3,099			2,215			93,530			20,903
December 31, 2010		2,805			9,506			75,650			24,920
January 1, 2011		2,805			9,506			75,650			24,920
December 31, 2011		12,509			15,178			94,064			43,365
January 1, 2012		12,509			15,178			94,064			43,365
December 31, 2012		28,436			17,339			101,582			62,705

The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2012, 2011 and 2010:

Year Ended December 31, 2012

We produced 2.9 MMBoe during 2012, 99.4% of which is attributable to our assets in the Permian Basin. Extensions and discoveries of 38.9 MMBoe for 2012 were primarily attributable to ongoing development of Project Pangea in the Wolfcamp oil shale resource play in the Permian Basin. We recorded downward revisions of 17.5 MMBoe to the December 31, 2011, estimates of our proved reserves at year end 2012. Downward revisions of 17.5 MMBoe include 8.9 MMBoe of deeper, Canyon reserves in southeast Project Pangea that we reclassified to probable undeveloped. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper Canyon locations beyond five years from initial booking is necessary in order to integrate their development with shallower Wolffork target zones. Revisions in 2012 also include [3.3] MMBoe of performance revisions related to vertical Canyon wells in Project Pangea, 2.9 MMBoe of revisions resulting from technical evaluations and 2.4 MMBoe of revisions resulting from lower natural gas and NGL prices in 2012.

Year Ended December 31, 2011

We produced 2.4 MMBoe during 2011, 99% of which is attributable to our assets in the Permian Basin. Extensions and discoveries of 25.5 MMBoe for 2011 include 24.2 MMBoe attributable to our Wolfcamp oil shale resource play in the Permian Basin. During 2011, we acquired approximately 10.5 MMBoe of proved reserves through the 38% Working Interest Acquisition. We recorded downward revisions of 7.5 MMBoe to the December 31, 2010, estimates of our proved reserves at year end 2011. Downward revisions of 7.5 MMBoe include 5.6 MMBoe of economic revisions in southeast Project Pangea in the Permian Basin and 2.2 MMBoe of proved undeveloped reserves in the East Texas Basin that, due to ongoing, low natural gas prices, we did not expect to develop by year-end 2013. Also included in the revisions were 0.3 MMBoe of positive revisions resulting from higher oil and NGL prices using the average 12-month price in 2011.

Year Ended December 31, 2010

Our drilling and development activities in Project Pangea in the Permian Basin resulted in our classification of reserves as proved, which accounts for the additional quantities listed under extensions and discoveries. For the year ended December 31, 2010, we recorded a 10.1 MMBoe positive revision to our previous estimate, resulting from 9.2 MMBoe attributable to planned processing upgrades in southeast Project Pangea and 1.1 MMBoe attributable to an increase in commodity prices, partially offset by 0.2 MMBoe of negative performance revisions. On April 1, 2011, we began realizing NGL revenues from the natural gas production in southeast Project Pangea under a gas purchase and processing contract with DCP Midstream, LP. The commodity prices used to estimate our proved reserves at December 31, 2010, increased to $4.38/MMBtu of gas, $39.25/Bbl of NGLs and $79.40/Bbl of oil from $3.87/MMBtu of natural gas, $27.20/Bbl of NGLs and $56.04/Bbl of oil at December 31, 2009. The negative revision of 0.1 MMBoe, primarily related to producing properties in our North Bald Prairie field in the East Texas Basin. Well performance data collected during 2010 for North Bald Prairie indicated that these assets underperformed our year-end 2010 decline estimates. Accordingly, we removed 0.9 Bcf (0.2 MMBoe) from proved reserves recorded for North Bald Prairie. We also removed 0.1 MMBoe in Project Pangea due to performance revisions.

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, 2012, 2011 and 2010:


	Years Ended December 31,
	2012			2011			2010
Future cash flows	$	4,920,231		$	3,772,633		$	1,804,477
Future production costs		(1,220,403	)		(1,012,044	)		(499,321	)
Future development costs		(1,025,193	)		(625,994	)		(259,005	)
Future income tax expense		(692,528	)		(583,961	)		(282,628	)

Future net cash flows		1,982,107			1,550,634			763,523
10% annual discount for estimated timing of cash flows		(1,487,887	)		(1,136,253	)		(559,291	)

Standardized measure of discounted future net cash flows	$	494,220		$	414,381		$	204,232

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,
	2012			2011			2010
Balance, beginning of period	$	414,381		$	204,232		$	79,991
Net change in sales and transfer prices and in production (lifting) costs related to future production		147,421			334,104			120,520
Changes in estimated future development costs		(486,435	)		(395,037	)		(65,718	)
Sales and transfers of oil and gas produced during the period		(100,634	)		(89,253	)		(46,031	)
Net change due to extensions, discoveries and improved recovery		467,822			291,501			30,240
Net change due to purchase of minerals in place		—			119,780			15,696
Net change due to revisions in quantity estimates		(210,296	)		(84,988	)		80,564
Previously estimated development costs incurred during the period		285,039			182,522			40,265
Accretion of discount		60,162			32,793			17,166
Other		(11,281	)		(38,107	)		4,171
Net change in income taxes		(71,959	)		(143,166	)		(72,632	)

Standardized measure of discounted future net cash flows	$	494,220		$	414,381		$	204,232