NOTE 13-SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities-Oil and Gas.

Geographical Data

The following table shows the Company's oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area:

	2011		2010		2009
Revenues
North America	$	148,266	$	206,591	$	171,922
South America		1,007,912		19,302,303		7,944,353
	$	1,156,178	$	19,508,894	$	8,116,275

Production Cost
North America	$	59,072	$	54,214	$	80,717
South America		795,247		8,088,230		4,665,578
	$	854,319	$	8,142,444	$	4,746,295

Capital Costs

Capitalized costs and accumulated depletion relating to the Company's oil and gas producing activities as of December 31, 2011, all of which are onshore properties located in the United States and Colombia, South America are summarized below:

	United States			South America			Total
Unproved properties not being amortized	$	862,049		$	22,028,895		$	22,890,944
Proved properties being amortized		851,357			1,638,807			2,490,164
Accumulated depreciation, depletion, amortization and impairment		(800,531	)		(829,792	)		(1,630,323	)

Net capitalized costs	$	912,875		$	22,837,910		$	23,750,785

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $4.22 for the United States and $15.73 for South America for the year ended December 31, 2011.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2011, 2010 and 2009 are summarized below:

	2011
	United States		South America
Property acquisition costs:
Proved	$	-	$	-
Unproved		250,702		2,279,230
Exploration costs		-		10,109,551
Development costs		-		641,375

Total costs incurred	$	250,702	$	13,030,156

	2010
	United States		South America
Property acquisition costs:
Proved	$	-	$	-
Unproved		312,921		-
Exploration costs		-		7,017,816
Development costs		-		1,331,779

Total costs incurred	$	312,921	$	8,349,595

	2009
	United States		South America
Property acquisition costs:
Proved	$	106,875	$	-
Unproved		1,010,941		2,560,808
Exploration costs		335,070		2,505,497
Development		-		1,754,354

Total costs incurred	$	1,452,886	$	6,820,659

Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with the new reserve estimation and disclosure rules. Disclosures by geographic area include the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company's reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that 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 those expected to be recovered through existing wells, equipment, and operating methods.

The reserve estimates set forth below were prepared by Lonquist & Co., LLC (Lonquist), utilizing reserve definitions and pricing requirements prescribed by the SEC. Lonquist is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist's report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist & Co. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin and is a registered professional engineer with more than 29 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management. Lonquist and its employees have no interest in the Company, and were objective in determining the results of the Company's reserves. Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties.

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

	United States						South America					Total
	Gas (mcf)			Oil (bbls)			Gas (mcf)		Oil (bbls)			Gas (mcf)			Oil (bbls)
Total proved reserves
Balance December 31, 2008		18,774			1,941			-		211,475			18,774			213,416

Extensions and discoveries		15,703			44			-		1,104,041			15,703			1,104,085
Purchase of minerals in place		42,685			1,394			-		-			42,685			1,394
Revisions of prior estimates		8,772			1,100			-		16,493			8,772			17,593
Production		(15,761	)		(1,581	)		-		(129,782	)		(15,761	)		(131,363	)

Balance December 31, 2009		70,173			2,898			-		1,202,227			70,173			1,205,125

Extensions and discoveries		-			-			-		129,197			-			129,197
Purchase of minerals in place		-			-			-		-			-
Revisions of prior estimates		29,845			4,652			-		26,217			29,845			30,869
Sales of minerals in place		-			-			-		(1,036,252	)		-			(1,036,252	)
Production		(17,798	)		(1,540	)		-		(260,239	)		(17,798	)		(261,779	)

Balance December 31, 2010		82,220			6,010			-		61,150			82,220			67,160

Extensions and discoveries		-			-			-		45,889			-			45,889
Purchase of minerals in place		-			-			-		-			-			-
Revisions of prior estimates		15,418			1,622					(2,496	)		15,418			(874	)
Production		(10,838	)		(1,092	)		-		(9,924	)		(10,838	)		(11,016	)

Balance December 31, 2011		86,800			6,540			-		94,619			86,800			101,159

Proved developed reserves
at December 31, 2009		70,173			2,898			-		307,993			70,173			310,891
at December 31, 2010		82,220			6,010			-		17,202			82,220			23,212
at December 31, 2011		86,800			6,540			-		30,845			86,800			37,385

Proved undeveloped reserves
at December 31, 2009		-			-			-		894,234			-			894,234
at December 31, 2010		-			-			-		43,948			-			43,948
at December 31, 2011		-			-			-		63,774			-			63,774

During 2011 and 2010, the Company recorded extensions and discoveries resulting principally from its ongoing drilling operations in Colombia. As of December 31, 2011, our proved undeveloped (“PUD”) reserves totaled 63,774 bbls of oil and 0 mcf of natural gas, for a total of 63,774 boe. Negative revisions of 11,805 boe in PUD reserves during 2011 were due to the ongoing drilling program and subsequent changes in subsurface mapping. None of the PUD reserves as of December 31, 2010 were converted to proved developed producing reserves in 2011. All PUD locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2016. None of our PUD locations have been booked for longer than five years.

Positive revisions of 129,197 boe in PUD reserves during 2010 were due to the on-going drilling program and subsequent changes in subsurface mapping.

Sales of reserves in place during 2010 represent the December 2010 transaction whereby entities owned 12.5% by the Company sold entities that held all of the Company's interest in the Dorotea, Cabiona, Leona and Las Garzas blocks in Colombia.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

Standardized measure of discounted future net cash flows at December 31, 2011:

	United States			South America			Total
Future net cash flow	$	1,074,280		$	8,996,185		$	10,070,465
Future production cost		(333,520	)		(4,202,604	)		(4,536,124	)
Future development cost		(48,320	)		(625,113	)		(673,433	)
Future income tax		(13,790	)		(821,537	)		(835,327	)

10% annual discount for timing of cash flow		(275,440	)		(697,102	)		(972,542	)

Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	403,210		$	2,649,829		$	3,053,039

Changes in standardized measure:
Change due to current year operations Sales, net of production costs		(89,168	)		(212,666	)		(301,834	)
Change due to revisions in standardized variables:
Income taxes		(13,790	)		(821,537	)		(835,327	)
Accretion of discount		43,962			161,839			205,801
Net change in sales and transfer price, net of production costs		26,770			328,994			355,764
Previously estimated development costs incurred during the period		-			641,375			641,375
Changes in estimated future development costs		-			(494,665	)		(494,665	)
Revision and others		86,695			(91,917	)		(5,222	)
Discoveries		-			1,594,813			1,594,813
Sales of reserves in place		-			-			-
Changes in production rates and other		(90,878	)		426,332			335,454

Net								1,496,159
Beginning of year								1,556,880

End of year							$	3,053,039

Standardized measure of discounted future net cash flows at December 31, 2010:

	United States			South America			Total
Future net cash flow	$	900,040		$	4,724,278		$	5,624,318
Future production cost		(279,710	)		(2,021,273	)		(2,300,983	)
Future development cost		-			(636,275	)		(636,275	)
Future income tax		-			(501,125	)		(501,125	)

10% annual discount for timing of cash flow		(180,710	)		(448,345	)		(629,055	)

Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	439,620		$	1,117,260		$	1,556,880

Changes in standardized measure:
Change due to current year operations Sales, net of production costs		(152,377	)		(11,214,073	)		(11,366,450	)
Change due to revisions in standardized variables:
Income taxes		-			(392,431	)		(392,431	)
Accretion of discount		32,397			1,549,659			1,582,056
Net change in sales and transfer price, net of production costs		224,620			22,861,606			23,086,226
Previously estimated development costs incurred during the period		-			1,336,231			1,336,231
Changes in estimated future developments costs		-			10,235,689			10,235,689
Revision and others		14,680			1,877,525			1,892,205
Discoveries		-			728,856			728,856
Sales of reserves in place		-			(29,750,509	)		(29,750,509	)
Changes in production rates and other		(3,691	)		(10,614,782	)		(10,618,473	)

Net								(13,266,600	)
Beginning of year								14,823,480

End of year							$	1,556,880

Standardized measure of discounted future net cash flows at December 31, 2009

	United States			South America			Total
Future net cash flow	$	455,522		$	66,715,086		$	67,170,608
Future production cost		(87,192	)		(36,712,770	)		(36,799,962	)
Future development cost					(11,571,920	)		(11,571,920	)
Future income tax		-			(1,560,871	)		(1,560,871	)
10% annual discount for timing of cash flow		(44,363	)		(2,370,012	)		(2,414,375	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	323,967		$	14,499,513		$	14,823,480

Changes in standardized measure:
Change due to current year operations Sales, net of production costs		(91,205	)		(3,278,775	)		(3,369,980	)
Change due to revisions in standardized variables:
Income taxes		-			(1,312,411	)		(1,312,411	)
Accretion of discount		10,361			351,301			361,662
Net change in sales and transfer price, net of production costs		(21,603	)		3,899,640			3,878,037
Previously estimated development costs incurred during the period		335,070			4,259,860			4,594,930
Changes in estimated future developments costs		(335,070	)		(3,526,367	)		(3,861,437	)
Revision and others		70,166			289,606			359,772
Discoveries		51,631			13,602,240			13,653,871
Purchase of reserves in place		189,626			-			189,626
Changes in production rates and other		35,510			(2,857,593	)		(2,822,083	)

Net								11,671,987
Beginning of year								3,151,493
End of year							$	14,823,480