(10) Supplementary Financial Information for Oil and Gas Producing Activities

Results of Operations from Oil and Gas Producing Activities

The Company's natural gas interests consist of royalty and non-operating working interests in wells drilled on the Company's approximately 3,800 acres of land located in Johnson County, Texas in the Barnett Shale Formation. The Company also has royalty and non-operating working interests in wells drilled from drillsites on the Company's property under a lease covering approximately 538 acres of land contiguous to the Company's Johnson County, Texas property. The following sets forth certain information with respect to the Company's results of operations and costs incurred for its natural gas interests for the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010

Results of Operations
Revenues	$	7,121	$	12,878	$	7,425
Production and operating costs		1,891		2,269		1,421
Depreciation and depletion		1,291		1,402		1,172

Results of operations before income taxes		3,939		9,207		4,832
Income tax expense		1,044		2,664		1,410

Results of operations (excluding corporate overhead and interest costs)	$	2,895	$	6,543	$	3,422

Costs Incurred
Development costs incurred	$	81	$	927	$	2,204
Exploration costs		—		—		—
Capitalized asset retirement costs		—	$	3	$	3
Property acquisition costs		—		—		—
Capitalized Costs
Natural gas properties—proved	$	18,301	$	18,220	$	17,295
Less: accumulated depreciation and depletion		7,294		5,997		4,593

Net capitalized costs for natural gas properties	$	11,007	$	12,223	$	12,702

Unaudited Oil and Natural Gas Reserve and Standardized Measure Information

The independent petroleum engineering firm of DeGolyer and MacNaughton has been retained by the Company to estimate its proved natural gas reserves as of December 31, 2012. No events have occurred since December 31, 2012 that would have a material effect on the estimated proved reserves.

The following information is presented with regard to the Company's natural gas reserves, all of which are proved and located in the United States. These rules require inclusion, as a supplement to the basic financial statements, of a standardized measure of discounted future net cash flows relating to proved natural gas reserves. The standardized measure, in management's opinion, should be examined with caution. The basis for these disclosures is independent petroleum engineers' reserve studies, which contain imprecise estimates of quantities and rates of production of reserves. Revision of estimates can have a significant impact on the results. Also, development and production improvement costs in one year may significantly change previous estimates of proved reserves and their valuation. Values of unproved properties and anticipated future price and cost increases or decreases are not considered. Therefore, the standardized measure is not necessarily a "best estimate" of the fair value of gas properties or of future net cash flows.

In calculating the future net cash flows for its royalty and non-operating working interests in the table below as of December 31, 2012, 2011 and 2010, the Company utilized 12-month average prices, as now required by US GAAP, of $2.87, $4.46 and $4.52 per MCF of natural gas and $30.27, $49.58 and $38.71 per BBL of natural gas liquids, respectively. Utilizing year-end prices of natural gas and natural gas liquids as of December 31, 2012, 2011 and 2010 would have resulted in proved reserves of 10.1, 10.2 and 13.1 BCF of natural gas and 1.5, 1.5 and 1.3 MMBBLS of natural gas liquids, respectively.

Unaudited Summary of Changes in Proved Reserves

	Natural Gas (BCF)			Natural Gas Liquids (MMBBLS)			Natural Gas (BCF)			Natural Gas Liquids (MMBBLS)			Natural Gas (BCF)			Natural Gas Liquids (MMBBLS)

	2012			2012			2011			2011			2010			2010
Proved reserves—beginning of year		10.3			1.5			12.3			1.2			13.3			1.8
Revisions of previous estimates		(0.8	)		(0.3	)		(0.8	)		0.5			(0.6	)		(0.6	)
Extensions and discoveries		—			—			—			—			0.4			—
Production		(1.2	)		(0.1	)		(1.2	)		(0.2	)		(0.8	)		—

Proved reserves—end of year		8.3			1.1			10.3			1.5			12.3			1.2

Proved developed reserves—end of year		8.3			1.1			10.3			1.5			11.7			1.2

Unaudited Standardized Measure of Discounted Future Net Cash Flows

	2012			2011			2010

Future estimated gross revenues	$	57,882		$	120,920		$	102,198
Future estimated production and development costs		(23,905	)		(32,138	)		(31,406	)

Future estimated net revenues		33,977			88,782			70,792
Future estimated income tax expense		(9,193	)		(25,627	)		(20,174	)

Future estimated net cash flows		24,784			63,155			50,618
10% annual discount for estimated timing of cash flows		(12,020	)		(33,207	)		(24,162	)

Standardized measure of discounted future estimated net cash flows	$	12,764		$	29,948		$	26,456

Unaudited Changes in Standardized Measure of Discounted Future Net Cash Flows

	2012			2011			2010

Standardized measure—beginning of year	$	29,948		$	26,456		$	23,076
Net change in sales prices and production costs		(7,067	)		2,403			8,689
Sales of natural gas produced, net of production costs		(5,230	)		(7,805	)		(5,992	)
Extensions and discoveries, net of related costs		—			—			1,737
Future development costs		—			—			(716	)
Net change due to changes in quantity estimates		(5,863	)		4,086			(5,488	)
Previously estimated development costs incurred		116			925			1,549
Net change in income taxes		7,419			(1,609	)		(1,237	)
Accretion of discount		1,603			3,211			2,962
Timing of production of reserves and other		(8,162	)		2,281			1,876

Standardized measure—end of year	$	12,764		$	29,948		$	26,456