15. Supplemental Oil and Gas Information (unaudited)

Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were located in the United States.

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2017 and 2016 (in thousands):



	Years Ended December 31,
	2017		2016
Proved oil and gas properties	$	5,704	$	5,315
Unproved properties		—		106
Total proved and unproved oil and gas properties	$	5,704	$	5,421
Less accumulated depreciation, depletion and amortization		(984)		(196)
Net oil and gas properties	$	4,720	$	5,225

As a result of the ceiling test impairments during 2015 and the first three quarters of 2016, the accumulated depreciation, depletion, and amortization was been netted against the cost to reflect the post impairment value of the oil and gas properties. As no ceiling test impairment was recorded during the quarter ended December 31, 2016, nor during any of the quarters ended in 2017, these amounts were not netted against cost, but remained in accumulated depreciation, depletion, and amortization at December 31, 2017 and December 31, 2016.

Oil and Gas Related Costs

The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands):



	Years Ended December 31,
	2017		2016		2015
Property acquisitions proved	$	—	$	—	$	—
Property acquisitions unproved		93		8		90
Exploration cost		69		396		22
Development cost		—		—		252
Total	$	162	$	404	$	364

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands):



	Years Ended December 31,
	2017		2016		2015
Revenues	$	4,683	$	4,113	$	5,631
Production costs and taxes		(3,444)		(3,064)		(3,731)
Depreciation, depletion and amortization		(796)		(1,009)		(2,538)
Impairment		—		(2,805)		(14,526)
Income (loss) from oil and gas producing activities	$	443	$	(2,765)	$	(15,164)

In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forward position.

Estimated Quantities of Oil and Gas Reserves

The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2015, 2016 and 2017. All of the Company’s proved reserves are located in the United States of America.



	Oil (MBbl)	Gas (MMcf)	MBOE
Proved reserves at December 31, 2014	1,797	—	1,797
Revisions of previous estimates	(790)	—	(790)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	1	—	1
Production	(131)	—	(131)
Sales of reserves in place	—	—	—
Proved reserves at December 31, 2015	877	—	877
Revisions of previous estimates	(36)	—	(36)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	3	—	3
Production	(108)	—	(108)
Sales of reserves in place	(6)	—	(6)
Proved reserves at December 31, 2016	730	—	730
Revisions of previous estimates	195	—	195
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	47	—	47
Production	(102)	—	(102)
Sales of reserves in place	—	—	—
Proved reserves at December 31, 2017	870	—	870

Proved developed reserves at:
December 31, 2014	1,438	—	1,438
December 31, 2015	877	—	877
December 31, 2016	730	—	730
December 31, 2017	832	—	832

Proved undeveloped reserves at:
December 31, 2014	359	—	359
December 31, 2015	—	—	—
December 31, 2016	—	—	—
December 31, 2017	38	—	38

The Company’s Proved Undeveloped Reserves at December 31, 2017 included 3 locations, and December 31, 2016 and 2015 included no locations as compared to 27 locations at December 31, 2014. During 2016 and 2015, all Proved Undeveloped locations were removed from the Company’s Proved Reserves primarily due to the low oil prices experienced during these years. During 2017, increases in prices allowed the company to include 3 Proved Undeveloped locations in its December 31, 2017 reserves.

The following table identifies the reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands):



	Year Ended 12/31/2017						Year Ended 12/31/2016						Year Ended 12/31/2015
	Oil		Gas		Total		Oil		Gas		Total		Oil		Gas		Total
Total proved reserves year-end reserve report	$	8,170		—	$	8,170	$	5,815		—	$	5,815	$	8,287		—	$	8,287
Proved developed producing reserves (PDP)	$	7,065		—	$	7,065	$	5,397		—	$	5,397	$	7,686		—	$	7,686
% of PDP reserves to total proved reserves		87%		—		87%		93%		—		93%		93%		—		93%
Proved developed non- producing reserves	$	1,082		—	$	1,082	$	418		—	$	418	$	601		—	$	601
% of PDNP reserves to total proved reserves		13%		—		13%		7%		—		7%		7%		—		7%
Proved undeveloped reserves (PUD)	$	23		—	$	23	$	—		—	$	—	$	—		—	$	—
% of PUD reserves to total proved reserves		—		—		—		—		—		—		—		—		—

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands):



	Years Ended December 31,
	2017		2016		2015
Future cash inflows	$	39,889	$	27,253	$	38,566
Future production costs and taxes		(23,343)		(16,270)		(23,500)
Future development costs		(1,586)		(553)		(951)
Future income tax expenses		—		—		—
Future net cash flows		14,960		10,430		14,115

Discount at 10% for timing of cash flows		(6,790)		(4,615)		(5,828)
Standardized measure of discounted future net cash flows	$	8,170	$	5,815	$	8,287

The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands):



	Years Ended December 31,
	2017		2016		2015
Balance, beginning of year	$	5,815	$	8,287	$	34,531
Sales, net of production costs and taxes		(1,239)		(2,037)		(1,901)
Discoveries and extensions, net of costs		123		35		5
Purchase of reserves in place		—		—		—
Sale of reserves in place		—		(10)		—
Net changes in prices and production costs		1,780		(863)		(16,009)
Revisions of quantity estimates		1,611		(412)		(22,431)
Previously estimated development cost incurred during the year		—		—		—
Changes in future development costs		(228)		196		4,890
Changes in timing and other		(164)		(20)		(56)
Accretion of discount		472		639		3,373
Net change in income taxes		—		—		5,885
Balance, end of year	$	8,170	$	5,815	$	8,287

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average sales prices, along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2017, 2016, and 2015 were $45.83, and $37.35, and $43.98 per barrel of oil, respectively. The Company’s proved reserves as of December 31, 2017, 2016 and 2015 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.