(11) Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)

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, 2014, 2013 and 2012:

	2014		2013		2012
Results of Operations
Revenues	$	5,274	$	5,762	$	7,121
Production and operating costs		1,546		1,920		1,891
Depreciation and depletion		895		955		1,291

Results of operations before income taxes		2,833		2,887		3,939
Income tax expense		742		736		1,044

Results of operations (excluding corporate overhead and interest costs)	$	2,091	$	2,151	$	2,895


Costs Incurred
Development costs incurred	$	25	$	58	$	81
Exploration costs		—		—		—
Capitalized asset retirement costs		—		—		—
Property acquisition costs		—		—		—
Capitalized Costs
Natural gas properties—proved	$	18,384	$	18,359	$	18,301
Less: accumulated depreciation and depletion		9,153		8,256		7,294

Net capitalized costs for natural gas properties	$	9,231	$	10,103	$	11,007

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, 2014. No events have occurred since December 31, 2014 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 the 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, 2014, 2013 and 2012, the Company utilized 12-month average prices of $4.61, $3.88 and $2.87 per MCF of natural gas and $30.20, $29.95 and $30.27 per BBL of natural gas liquids, respectively.

Unaudited Summary of Changes in Proved Reserves

	Natural Gas (BCF) 2014			Natural Gas Liquids (MMBBLS) 2014			Natural Gas (BCF) 2013			Natural Gas Liquids (MMBBLS) 2013			Natural Gas (BCF) 2012			Natural Gas Liquids (MMBBLS) 2012
Proved reserves—beginning of year		7.6			1.1			8.3			1.1			10.3			1.5
Revisions of previous estimates		(0.3	)		—			—			0.1			(0.8	)		(0.3	)
Extensions and discoveries		—			—			—			—			—			—
Production		(0.6	)		(0.1	)		(0.7	)		(0.1	)		(1.2	)		(0.1	)

Proved reserves—end of year		6.7			1.0			7.6			1.1			8.3			1.1


Proved developed reserves—end of year		6.7			1.0			7.6			1.1			8.3			1.1

Unaudited Standardized Measure of Discounted Future Net Cash Flows

	2014			2013			2012
Future estimated gross revenues	$	60,073		$	61,873		$	57,882
Future estimated production and development costs		(23,243	)		(24,276	)		(23,905	)

Future estimated net revenues		36,830			37,597			33,977
Future estimated income tax expense		(10,105	)		(10,286	)		(9,193	)

Future estimated net cash flows		26,725			27,311			24,784
10% annual discount for estimated timing of cash flows		(13,437	)		(13,733	)		(12,020	)

Standardized measure of discounted future estimated net cash flows	$	13,288		$	13,578		$	12,764

Unaudited Changes in Standardized Measure of Discounted Future Net Cash Flows

	2014			2013			2012
Standardized measure—beginning of year	$	13,578		$	12,764		$	29,948
Net change in sales prices and production costs		2,180			4,227			(7,067	)
Sales of natural gas produced, net of production costs		(3,730	)		(3,842	)		(5,230	)
Net change due to changes in quantity estimates		(586	)		430			(5,863	)
Previously estimated development costs incurred		21			56			116
Net change in income taxes		90			(380	)		7,419
Accretion of discount		1,594			1,486			1,603
Timing of production of reserves and other		141			(1,163	)		(8,162	)

Standardized measure—end of year	$	13,288		$	13,578		$	12,764