NOTE 14—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:

	2012		2011
Revenues
North America	$	148,163	$	148,266
South America		263,186		1,007,912
	$	411,349	$	1,156,178

		2012		2011
Production Cost
North America	$	76,593	$	59,072
South America		118,788		795,247
	$	195,381	$	854,319

Capital Costs

Capitalized costs and accumulated depletion relating to the Company's oil and gas producing activities as of December 31, 2012, 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	$	972,885	$	4,836,412		$	5,809,297
Proved properties being amortized		857,845		46,235,574			47,093,419
Accumulated depreciation, depletion, amortization and impairment		(807,688)		(46,235,574	)		(47,043,262)

Net capitalized costs	$	1,023,042	$	4,836,412		$	5,859,454

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $1.88 for the United States and $9.52 for South America for the year ended December 31, 2012.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2012 and 2011 are summarized below:

	2012
	United States		South America
Property acquisition costs:
Proved	$	—	$	—
Unproved		110,836
Exploration costs		—		25,915,741
Development costs		6,488

Total costs incurred	$	117,324		25,915,741

	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

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. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin and is a registered professional engineer with more than 30 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, 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

Purchase of minerals in place
Revisions to prior estimates		10,546			662			—		253			10,546			915
Sales of minerals in place		—			—			—		(93,117	)		—			(93,117	)
Production		(12,066	)		(1,032	)		—		(1,755	)		(12,066	)		(2,787	)

Balance December 31, 2012		85,280			6,170			—		0			85,280			6,170

Proved developed reserves
at December 31, 2011		86,800			6,540			—		30,845			86,800			37,385
at December 31, 2012		85,280			6,170			—		-			85,280			6,170

Proved undeveloped reserves
at December 31, 2011		—			—			—		63,774			—			63,774
at December 31, 2012		—			—			—		—			—			—

During 2012 and 2011, the Company recorded extensions and discoveries resulting principally from its ongoing drilling operations in Colombia. As of December 31, 2012, we had no proved undeveloped ("PUD") reserves. None of the PUD reserves as of December 31, 2011 were converted to proved developed producing reserves in 2012. All remaining PUD reserves as of December 31, 2011 were sold during 2012 in connection with the sale of our indirect 1.6% ownership in an entity holding interests in the La Cuerva and LLA 62 blocks in Colombia.

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.

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, 2012:

	United States		South America		Total
Future cash inflows from sales of oil and gas	$	921,070	$	—	$	921,070
Future production cost		(392,430)		—		(392,430)
Future development cost		—		—		—
Future income tax		—		—		—
		528,640				528,640

10% annual discount for timing of cash flow		(230,570)		—		(230,570)

Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	298,070	$	0	$	298,070

Changes in standardized measure:
Change due to current year operations Sales, net of production costs		(71,570)		(144,398)		(215,968)
Change due to revisions in standardized variables:
Income taxes		(12,911)		—		(12,911)
Accretion of discount		49,238		—		49,238
Net change in sales and transfer price, net of production costs		(62,724)		—		(62,724)
Previously estimated development costs incurred during the period		—		—		—
Changes in estimated future development costs		—		—		—
Revision and others		35,781		—		35,781
Discoveries		—		—		—
Sales of reserves in place		—		(2,505,431)		(2,505,431)
Changes in production rates and other		(42,954)		—		(42,954)

Net						(2,754,969)
Beginning of year						3,053,039

End of year					$	298,070

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

	United States		South America		Total
Future cash flows from sales of oil and gas	$	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)
Future net cash flows		678,650		3,346,931		4,025,581

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