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,
	2014			2013
Revenues	$	695,318		$	735,413
Costs incurred:
Exploration and dry hole costs	56,351			112,123
Lease operating costs and production taxes	225,074			247,350
Impairment of oil and natural gas reserves	3,721,042			640,583
Depletion, depreciation and accretion	430,912			378,398
Totals, costs incurred	4,433,379			1,378,454
Pre-tax (loss) from producing activities	(3,738,061		)	(643,041		)
Results (loss) from of oil and natural gas producing activities (excluding overhead, income taxes, and interest costs)	$	(3,738,061	)	$	(643,041	)

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,
	2014		2013
Property acquisition and developmental costs:
Development	$	841,270	$	2,346,482
Property Acquisition	3,214,872		81,550
Undrilled leaseholds	22,577		—
Asset retirement obligations	3,721		8,930
Totals costs incurred	$	4,082,440	$	2,436,962

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, 2014 and 2013 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 SFAS 69 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, 2014 and December 31, 2013 are shown below:



	Years Ended December 31,
Volumes	2014		2013
Natural gas:	(Mcfs)
Proved developed and undeveloped reserves (mcf):
Beginning of year	723,190		679,410
Purchase (sale) of natural gas properties in place	(46,770	)	(6,004	)
Discoveries and extensions	—		66,680
Revisions	(30,843	)	27,937
Production	(45,577	)	(44,833	)
Proved reserves, at end of year (a)	600,000		723,190



	Years Ended December 31,
	2014		2013
Oil:	(Bbls)
Proved developed and undeveloped reserves:
Beginning of year	49,020		24,290
Purchase (sale) of oil producing properties in place	(26,290	)	(2,430	)
Discoveries and extensions	1,175		30,550
Revisions	3,700		2,420
Production	(6,905	)	(5,810	)
Proved reserves, at end of year (a)	20,700		49,020


(a)	Includes 300,000 Mcf and 10,350 bbl and 361,595 Mcf and 24,510 bbl for the twelve months ended December 31, 2014 and 2013, respectively of proved reserves attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.



	Years Ended December 31,
Values	2014			2013
Future cash inflows	$	4,920,190		$	8,174,120
Future costs:
Production	2,144,600			(3,387,700		)
Development	87,650			(555,650		)
Future cash flows	2,687,940			4,230,770
10% annual discount for estimated timing of cash flow	(1,223,370		)	1,808,670
Standardized measure of discounted cash flow (a)	$	1,464,570		$	2,422,100


(a)	Includes $732,285 and $1,211,050 for the twelve months ended December 31, 2014 and 2013, 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 2014, the gas and oil prices for this analysis were set at the average price received on the “first-day-of-the-month” for 2014, for appropriate differentials. The “benchmark” prices are $94.99 per barrel and $4.35 per Mcf. The average quarterly quarterly price received for natural gas for 2014 ranged from $4.55 /Mcf to $5.97 /Mcf . The average quarterly price received oil for 2014 ranged from $58.70/bbl to $82.93/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,
	2014			2013
Increase (decrease)
Sale of gas and oil, net of operating expenses	$	(470,244	)	$	(473,159	)
Discoveries, extensions and improved recovery, net of future production and development costs	—			888,160
Accretion of discount	242,210			261,779
Net increase (decrease)	$	(228,034	)	$	676,780
Standardized measure of discounted future cash flows:
Beginning of the year	$	2,422,100		$	1,745,320

Before Income Taxes	$	1,464,570		$	2,422,100
Income Taxes	(500,586		)	(823,500		)
End of the year (a)	$	963,984		$	1,598,600


(a)	Includes $481,992 and $799,300 for the twelve months ended December 31, 2014 and 2013, respectively of future net cash flows attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.