(12) 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, 2016, 2015 and 2014:


	2016		2015		2014
Results of Operations
Revenues	$	2,092	$	2,447	$	5,274
Production and operating costs		1,164		1,259		1,546
Depreciation and depletion		868		874		895
Results of operations before income taxes		60		314		2,833
Income tax (benefit) expense		(93)		(19)		742
Results of operations (excluding corporate overhead and interest costs)	$	153	$	333	$	2,091
Costs Incurred
Development costs incurred	$	15	$	15	$	25
Exploration costs		—		—		—
Capitalized asset retirement costs		—		—		—
Property acquisition costs		—		—		—
Capitalized Costs
Natural gas properties-proved	$	18,412	$	18,398	$	18,384
Less: accumulated depreciation and depletion		10,900		10,030		9,153
Net capitalized costs for natural gas properties	$	7,512	$	8,368	$	9,231

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, 2016. No events have occurred since December 31, 2016 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, 2016, 2015 and 2014, the Company utilized 12‑month average prices of $2.65, $2.80 and $4.61 per MCF of natural gas and $16.61, $14.92 and $30.20 per BBL of natural gas liquids, respectively.

Unaudited Summary of Changes in Proved Reserves


		Natural Gas		Natural Gas		Natural Gas
	Natural	Liquids	Natural Gas	Liquids	Natural Gas	Liquids
	Gas (BCF)	(MMBBLS)	(BCF)	(MMBBLS)	(BCF)	(MMBBLS)
	2016	2016	2015	2015	2014	2014
Proved reserves - beginning of year	5.3	0.7	6.7	1.0	7.6	1.1
Revisions of previous estimates	(0.9)	(0.1)	(0.9)	(0.2)	(0.3)	—
Extensions and discoveries	—	—	—	—	—	—
Production	(0.5)	(0.1)	(0.5)	(0.1)	(0.6)	(0.1)
Proved reserves - end of year	3.9	0.5	5.3	0.7	6.7	1.0
Proved developed reserves - end of year	3.9	0.5	5.3	0.7	6.7	1.0

Unaudited Standardized Measure of Discounted Future Net Cash Flows


	2016		2015		2014
Future estimated gross revenues	$	17,908	$	25,916	$	60,073
Future estimated production and development costs		(8,402)		(12,019)		(23,242)
Future estimated net revenues		9,506		13,897		36,831
Future estimated income tax expense		(2,458)		(3,642)		(10,105)
Future estimated net cash flows		7,048		10,255		26,726
10% annual discount for estimated timing of cash flows		(2,851)		(4,969)		(13,438)
Standardized measure of discounted future estimated net cash flows	$	4,197	$	5,286	$	13,288

Unaudited Changes in Standardized Measure of Discounted Future Net Cash Flows


	2016		2015		2014
Standardized measure - beginning of year	$	5,286	$	13,288	$	13,578
Net change in sales prices and production costs		(1,403)		(12,535)		2,180
Sales of natural gas produced, net of production costs		(928)		(1,188)		(3,730)
Net change due to changes in quantity estimates		(1,732)		(2,625)		(586)
Previously estimated development costs incurred		—		14		21
Net change in income taxes		414		3,147		90
Accretion of discount		571		1,570		1,594
Timing of production of reserves and other		1,989		3,615		141
Standardized measure - end of year	$	4,197	$	5,286	$	13,288