Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)

The following disclosures provide unaudited information required by ASC 932, “Extractive Activities – Oil and Gas” on oil and natural gas producing activities. These disclosures include non-controlling interests in Aurora which is managed and owned 50% by Victory.

Results of operations from oil and natural gas producing activities (Successful Efforts Method)

The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:



	Years Ended December 31,
	2016		2015
Revenues	$	287,179	$	650,648
Costs incurred:
Exploration and dry hole costs	3,000		2,513
Lease operating costs and production taxes	119,935		192,504
Impairment of oil and natural gas reserves	—		867,048
Depletion, depreciation and accretion	125,744		637,121
Totals, costs incurred	248,679		1,699,186
Pre-tax income(loss) from producing activities	38,500		(1,048,538		)
Results income (loss) from of oil and natural gas producing activities (excluding overhead, income taxes, and interest costs)	$	38,500	$	(1,048,538	)

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31:



	Years Ended December 31,
	2016		2015
Property acquisition and developmental costs:
Development	$	18,442	$	1,058,704
Property Acquisition	—		—
Undrilled Leaseholds	—		—
Asset retirement obligations	—		2,506
Totals costs incurred	$	18,442	$	1,061,210

Oil and natural gas reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2016 and 2015 and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

Standardized measure of discounted future net cash flows relating to proven oil and gas reserves (SMOG)

The following information has been prepared in accordance with the Financial Accounting Standards Board pronouncements and the regulations of the Securities and Exchange Commission, which require the standardized measure of discounted future cash flows based on sales prices, costs and statutory interest rates. The standardized measure of oil and gas producing activities is the present value of estimated future cash inflow from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted to reflect timing of future cash flows.

The Company’s proved oil and natural gas reserves for the years ended December 31, 2016 and December 31, 2015 are shown below:



	Years Ended December 31,
Volumes	2016		2015
Natural gas:	(Mcfs)
Proved developed and undeveloped reserves (mcf):
Beginning of year	178,750		600,000
Purchase (sale) of natural gas properties in place	(6,168	)	—
Discoveries and extensions	—		—
Revisions	(30,794	)	(410,362	)
Production	(30,038	)	(37,568	)
Proved reserves, at end of year (a)	111,750		178,750



	Years Ended December 31,
	2016		2015
Oil:	(Bbls)
Proved developed and undeveloped reserves:
Beginning of year	41,380		20,700
Purchase (sale) of oil producing properties in place	(1,107	)	—
Discoveries and extensions	—		30,720
Revisions	(6,872	)	2,112
Production	(6,871	)	(12,152	)
Proved reserves, at end of year (a)	26,530		41,380


(a)	Includes 55,875 Mcf and 13,265 bbl and 89,375 Mcf and 20,690 bbl for the twelve months ended December 31, 2016 and 2015, respectively of proved reserves attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.



	Years Ended December 31,
Values	2016		2015
Future cash inflows	1,272,950		2,345,940
Future costs:
Production	(641,527	)	(964,520	)
Development	—		(87,650	)
Future cash flows	631,423		1,293,770
10% annual discount for estimated timing of cash flow	(159,123	)	(421,640	)
Standardized measure of discounted cash flow (a)	472,300		872,130


(a)	Includes 472,300 and 872,130 for the twelve months ended December 31, 2016 and 2015, respectively, of discounted cash flows attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.

Using the SEC adjusted guidelines in place for 2016, the gas and oil prices for this analysis were set at the average price received on the “first-day-of-the-month” for 2016, for appropriate differentials. The “benchmark” prices are $42.75 per barrel and $2.49 per Mcf. The average quarterly price received for natural gas for 2015 ranged from $1.72 /Mcf to $3.95 /Mcf . The average quarterly price received oil for 2016 ranged from $31.95/bbl to $42.56/bbl.

Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Changes in standardized measure

Included within standardized measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:



	For the years ended December 31,
	2016		2015

Balance, January 1	872,130		964,000
Net change in price and production costs (a)	(220,100	)	(235,300	)
Sale of oil and gas, net	(173,400	)	(455,600	)
Extensions/Discoveries	12,500		—
Purchase of reserves in place	—		531,700
Sales of reserves in place	(15,500	)	—
Revisions of previous estimates	(153,900	)	(803,900	)
Accretion of discount	87,200		146,500
Net change in taxes	—		500,600
Net change in timing and other	63,400		224,300
Balance, December 31	472,300		872,130


(a)	Includes 472,300 and 872,130 for the twelve months ended December 31, 2016 and 2015, respectively of future net cash flows attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.