Annual report pursuant to section 13 and 15(d)

NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development. Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	Fiscal Year Ended December 31, 2012		Fiscal Year Ended December 31, 2011
Property acquisitions
Unproved	$	-	$	-
Proved		475,000		-
Exploration		106,109		-
Development		1,617,526		-
Total Costs Incurred	$	2,198,635	$	-

Capitalized costs. Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds and geological and geophysical expenses where no proved reserves have been identified.

	December 31, 2012			December 31, 2011
Capitalized costs
Unproved properties	$	72,950			$	-
Proved properties		2,125,685				-
		2,198,635				-
Less: Accumulated DD&A		(28,291	)			-
Net capitalized costs	$	2,170,344			$	-

Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2012, by the period in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five years.

			Fiscal Year Ended
	Total		December 31, 2012

Property acquisition costs	$	-		$	-
Exploration and development		72,950			-
Capitalized interest		-			-
Total	$	72,950		$	-

Oil and Gas Reserve Information. Nova Resources, Inc., an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the leasehold interests as of December 31, 2012. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company's Proved Reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.

	Oil
	(Bbls)

December 31, 2011		-
Revisions of prior estimates		-
Purchases of reserves in place		220,995
Production		(1,381	)
December 31, 2012		219,614

	December 31, 2012		December 31, 2011

Estimated Quantities of Proved Developed Reserves – Oil (Bbls)		59,971		-
Estimated Quantities of Proved Undeveloped Reserves – Oil (Bbls)		159,643		-

Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.

Standardized Measure of Oil and Gas

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.

	December 31, 2012

Future cash inflows	$	20,863,274
Future production costs		(13,343,179	)
Future development costs		(2,400,000	)
Future income taxes		-

Future net cash flows		5,120,095
Discount of future net cash flows at 10% per annum		(679,338	)

Standardized measure of discounted future net cash flows	$	4,440,757

Standardized measure of discounted future net cash flows, beginning of year	$	-
Changes in the year resulting from:
Sales, less production costs		(51,254	)

Revisions of previous quantity estimates		-

Extensions, discoveries and other additions		-

Net change in prices and production costs		-

Changes in estimated future development costs		-
Previously estimated development costs incurred during the period		-
Purchases of minerals in place		4,492,011
Accretion of discount		-
Divestiture of Reserves		-
Net change in income taxes		-
Timing differences and other		-
Standardized measure of discounted future net cash flows, end of year	$	4,440,757