Gran Tierra Energy (GTE) 8-K Other Events

INDEX TO FINANCIAL STATEMENTS

			Page Number
Financial Statements for Argosy Energy International, LP as of March 31, 2006 and the period ended March 31, 2006 (Unaudited)			3

Statements of Income			3
Balance Sheets			4
Statements of Cash Flows			5
Statements of Partners’ Equity			6
Notes to Financial Statements			7

Financial Statements for Argosy Energy International, LP as of December 31, 2005 and 2004			21

Independent Auditors’ Report			21
Statements of Income			22
Balance Sheets			23
Statements of Cash Flows			24
Statements of Partners’ Equity			25
Notes to Financial Statements			26

Supplemental Oil and Gas Information (unaudited)			42

March 31, 2006 and the period ended March 31, 2006 (Unaudited)

Financial Statements

ARGOSY ENERGY INTERNATIONAL, LP

Statements of Income (Unaudited)

For the Three Months Ended March 31, 2006 and 2005

See accompanying notes to unaudited financial statements.

	2006		2005
Oil sales to Ecopetrol	$	3,575		1,521

Operating cost (note 8)		367		364
Depreciation, depletion and amortization		190		80
General and administrative expenses		282		148
		839		592
Operating profit		2,736		929

Other income, net		79		116
Income before income and remittance taxes		2,815		1,045

Current income tax (note 9)		1,017		370
Deferred remittance tax		109		42
Total income and remittance taxes		1,126		412
Net income	$	1,689		633

Balance Sheets (Unaudited)

March 31, 2006 and December 31, 2005

See accompanying notes to unaudited financial statements.

	March 31,		December 31,
Assets	2006		2005

Current assets:
Cash and cash equivalents (note 3)	$	2,670		7,124
Accounts receivable, net (note 4)		3,898		951
Accounts receivable reimbursement Ecopetrol		1,186		1,186
Inventories:
Crude oil		211		218
Materials and supplies		626		557
		837		775
Total current assets		8,591		10,036

Other long-term assets		25		16
Property, plant and equipment (note 5):
Unproved properties		3,831		3,622
Proved properties		5,305		5,401
		9,136		9,023
Total assets	$	17,752		19,075

Liabilities and Partners’ Equity

Current liabilities:
Accounts payable		4,852		4,979
Tax payable		1,721		1,326
Employee benefits		97		103
Accrued liabilities		547		522
Total current liabilities		7,217		6,930

Long-term accounts payable (note 10)		686		686
Deferred income tax		473		475
Deferred remittance tax		1,210		1,104
Pension plan		—		—
Total liabilities		9,586		9,195
Partners’ equity (note 7)		8,166		9,880
Total liabilities and partners’ equity	$	17,752		19,075

Statements of Cash Flows (Unaudited)

For the Three Months Ended March 31, 2006 and 2005

See accompanying notes to unaudited financial statements.

	2006			2005
Cash flows from operating activities:
Net income	$	1,689			633
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		190			80
Deferred remittance tax		109			42
Changes in assets and liabilities:
Accounts receivable		(3,147	)		(839	)
Inventories		(62	)		58
Accounts payable		(127	)		202
Tax payable		395			99
Employee benefits		(6	)		48
Accrued Liabilities		25			491
Deferred income tax		(2	)		1
Deferred remittance tax		(3	)		4
Pensions		—			(5	)
Net cash (used in) provided by operating activities		(939	)		814

Cash flows from investing activities:
Increase in long term investments		(9	)		(1	)
Payments from Petroleum Equipment International - Talora		200			—
Additions to property, plant and equipment		(303	)		(767	)
Net cash used in investing activities		(112	)		(768	)

Cash flows from financial activities:
Bank overdrafts		—			106
Distributions to partners		(3,250	)		—
Aviva redemption shares		(153	)		—
Net cash (used in) provided by financial activities		(3,403	)		106

(Decrease) increase in cash and cash equivalents		(4,454	)		152
Cash and cash equivalents at beginning of year		7,124			6,954
Cash and cash equivalents at end of the period	$	2,670			7,106

Statements of Partners’ Equity (Unaudited)

For the Three Months Ended March 31, 2006 and the Year Ended December 31, 2005

See accompanying notes to unaudited financial statements.

	Limited			General			Total
	partners’			partners’			partners’
	capital			capital			equity
Balance as of December 31, 2005		9,810			70			9,880
Redemption of partnership payments interest - Aviva Overseas Inc. (note 10)		(152	)		(1	)		(153	)
Distributions to partners		(3,227	)		(23	)		(3,250	)
Net income		1,677			12			1,689
Balance as of March 31, 2006	$	8,108			58			8,166

March 31, 2006 and 2005

(1)		Business Activities

		Argosy Energy International, LP is a Utah (USA) Limited Partnership, which established a Colombian Branch in 1983.

		Argosy Energy International, LP is engaged in the business of exploring for, developing and producing oil and gas. The principal properties and operations are located in Colombia, which are carried out through its Colombian Branch in the Putumayo, Cauca, Tolima and Cundinamarca Provinces. The oil production is sold to Empresa Colombiana de Petróleos, the Colombian National Oil Company, (“Ecopetrol”).

		There are risks involved in conducting oil and gas activities in remote, rugged and primitive regions of Colombia. The guerrillas have operated within Colombia for many years and expose the Company’s operations to potentially detrimental activities. The guerrillas are present in the Putumayo and Río Magdalena areas where the Company’s properties are located. Since 1998, the Company has only experienced minor attacks on pipelines and equipment.

		Operations

		As of March 31, 2006, Argosy was participating in the following Association Contracts signed with Ecopetrol and Exploration and Exploitation Contracts signed with the Hydrocarbons National Agency - ANH.

Contract

Participation

Operator

Phase

Santana

ARGOSY

Exploitation

Guayuyaco

ARGOSY

Exploitation

Aporte Putumayo

100

ARGOSY

Abandonment

Río Magdalena

ARGOSY

Exploration

Talora

ARGOSY

Exploration

Chaza

ARGOSY

Exploration

		The first four contracts have been signed with ECOPETROL and the last two with ANH.

		An association contracts are those where the Government participate as partner of the field through the national oil company — ECOPETROL.

		Exploration and production contracts (E&P) are those signed with the ANH — “Agencia Nacional de Hidrocarburos” (National Agency for Hydrocarbons) in which the Government only receive royalties and taxes for the rights of exploration and production but there is not a participation from the national oil company - ECOPETROL or any other government entity.

		The main terms of the above-mentioned contracts are as follows:

		Santana Association Contract

		On May 27, 1987 (effective date July 27, 1987), Argosy Energy International, LP signed this association contract to explore for and produce oil, in the area called Santana. The contract is in its 19th year and the Company reduced the area to a 5 kilometer reserve area around each field. The remaining contract area is approximately 1,100 acres.

		Under the terms of the contract with Ecopetrol, a minimum of 25% of all revenues from oil sold to Ecopetrol is paid in Colombian pesos, which may only be utilized in Colombia. However, this proportion can be modified through parties agreement.

		Aporte Putumayo - Association Contract

		The Aporte Putumayo area has been returned to the Government. Such devolution is subject to the approval of the environmental restoration of the region by the Environmental Ministry and the wells abandonment have to be approved by Ecopetrol and the Ministry of Mines.

		Río Magdalena Association Contract

		On December 10, 2001 (effective date February 8, 2002), Argosy Energy International, LP and Ecopetrol signed this Association Contract, to explore and produce oil, in the area called Río Magdalena of approximately 145,000 acres, located in the Middle Magdalena Valley of Colombia in the provinces of Cundinamarca and Tolima.

		The contract has a maximum duration of 28 years distributed as follows: an exploration period of 6 years and a production period of 22 years starting on the date of termination of the exploration period. The exploratory well, Popa-1 was drilled during June and July, 2006 and is on the completion stage.

		Upon finalization of each phase, Argosy has the option to relinquish the contract, once completed the obligations for each phase.

		BT Letter Agreement

		On February 27, 2001 Argosy Energy International, LP signed a letter agreement with BT Operating Company for the acquisition and management of the Río Magdalena Exploration Area. BT and Argosy mutually agreed to pay their 50% share of costs under the terms of the Ecopetrol Association contract and provide certain services toward management and compliance of the obligations.

		As of March 31, 2006 BT had not paid their obligations under this agreement and outstanding accounts receivable of $355 related to their share of cost related to the Río Magdalena Association Contract were provisioned as bad debts.

		Guayuyaco Association Contract

		On August 2, 2002 (effective date September 30, 2002) Argosy Energy International, LP signed this association contract with Ecopetrol, to explore and produce oil, in the area called Guayuyaco. This Association contract gives Argosy the right to explore potential reserves in prospects adjacent to the existing Santana oil field. The block is located in the Putumayo and Cauca provinces and covers approximately 52.000 acres originally held under the Santana Risk Sharing Agreement.

		The Guayuyaco contract has a maximum duration of 27.5 years with an exploration period of 5.5 years and a production period of 22 years, which starts upon termination of the exploration period.

		During the second exploration phase, two wells were drilled (Guayuyaco-1 and Guayuyaco-2) which were successful. Therefore, on December 28, 2005 Ecopetrol accepted the Commerciality of the field.

		Solana Petroleum Exploration Commercial Agreement

		Argosy and Solana Petroleum Exploration entered into a commercial agreement in 2003 whereby, Solana through fulfillment of certain obligations could earn a participating interest in the Inchiyaco Well Prospect (Santana Association Contract) and have an option to enter the next exploration prospect under the Guayuyaco Association Contract. Inchiyaco-1 was drilled and completed as a producing well in 2003 resulting in Solana’s sharing 26.21% interest in Argosy’s net share of the prospect.

		The commercial agreement was revised in 2004, giving Solana the right to share a 50% interest in Argosy’s net share of the Guayuyaco association contract by paying 66.7% of two exploratory wells (Guayuyaco-1 and Juanambu-1) and 50% for a new seismic program and additional projects.

		Talora Exploration and Exploitation Contract

		On September 16, 2004 (effective date) Argosy and the National Hydrocarbons Agency (ANH) signed the Talora Exploration and Exploitation Contract to explore and produce oil, in an area of approximately 108,000 acres located in Tolima and Cundinamarca Provinces.

		The contract has a maximum duration of 30 years with an exploration period of 6 years and a production period of 24 years, which starts upon the date in which Argosy receives the oil field commerciality declaration from ANH.

		The contract may be relinquished at the end of each phase after fulfillment of the agreed obligations.

		Argosy and Petroleum Equipment International (PEI) signed a commercial agreement on March 9, 2006. Through fulfillment of certain obligations PEI could earn an 80% of Argosy’s interest under the ANH contract on the Talora Block. In conjunction with such assignment, Argosy shall designate PEI as the operator previous approval of the ANH.

		Contractual Commitments:

Phase	Starting date	Obligations
3	December 16, 2006	One exploratory well.
4	December 16, 2007	One exploratory well.
5	December 16, 2008	One exploratory well.
6	December 16, 2009	One exploratory well.

		The contract may be relinquished at the end of each phase after fulfillment of the agreed obligations.

		Chaza Exploration and Exploitation Contract

		On June 27, 2005 (effective date) Argosy and the National Hydrocarbons Agency (ANH) signed the Chaza Exploration and Exploitation Contract to explore and produce oil, in an area of approximately 80,000 acres located in Putumayo and Cauca Provinces.

		The contract has a maximum duration of 30 years with an exploration period of 6 years and a production period of 24 years, which starts upon the date in which Argosy receives the oil field commerciality declaration from ANH.

		The ANH’s Resolution 0217, dated September 13, 2005, approved the 2005 assignment of 50% interest of the contract to Solana Petroleum Exploration.

		Contractual Commitments:


Phase	Starting date	Obligations
2	June 27, 2006	One exploratory well.
3	June 27, 2007	One exploratory well.
4	December 27, 2008	One exploratory well.
5	December 27, 2009	One exploratory well.
6	December 27, 2010	One exploratory well.

The contract may be relinquished at the end of each phase after fulfillment of the agreed obligations.

(2)

Summary of Significant Accounting Policies and Practices

		(a) Foreign Currency Translation
		The transactions and accounts of the Company’s operations denominated in currencies other than US dollars are re-measured into United States dollars in accordance with Statement of Financial Accounting Standards FAS 52. The United States dollar is used as the functional currency. Exchange adjustments resulting from foreign currency balances are recognized in expense or income in the current period.

		(b) Cash Equivalents
		Cash equivalents are highly liquid investments purchased with an original maturity of three months or less.

		(c) Inventories
		Inventories consist of crude oil and materials and supplies and are stated at the lower of cost or market.

		(d) Property, Plant and Equipment
		The Company follows the full cost method to account for exploration and development of oil and gas reserves whereby all productive and nonproductive costs are capitalized. The only cost center is Colombia. All capitalized costs plus the undiscounted future development costs of proved reserves are depleted using the unit of production method based on total proved reserves applicable to the country.

		Proved oil and gas reserves are the estimated quantities of crude oil that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions considering future production and development costs.

		Costs related to initial exploration activities with no proved reserves are initially capitalized and periodically evaluated for impairment. The Company capitalizes internal costs directly identified with exploration and development activities. The net capitalized costs of oil properties are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization.

		While the quantities of proved reserves require substantial judgment, the associated prices of oil reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of prices and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.

		Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a country.

		Support equipment and facilities are depreciated using the unit of production method based on total reserves of the field related to the support equipment and facilities.

		(e)Environmental Liabilities and Expenditures
		Argosy accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.

		(f) Asset Retirement Obligations
		Liability for asset retirement obligation is considered to be negligible at this time, based on projected production profiles, expiry dates and terms of the Association Contracts for current operations. However, the Company has accrued the costs related to environmental remediation and abandonment of the wells belonging to Aporte Putumayo Contract.

		(g) Concentration of Credit Risks
		All of the Company’s production is sold to Ecopetrol; the sale price is agreed between both parts, according to local regulations in Colombia.

		(h) Income Taxes
		Deferred income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

		(i) Financial Instruments Fair Value
		The carrying amounts of cash and cash equivalents approximate fair value because of the short maturity of those instruments. The carrying value of other on-balance-sheet financial instruments approximates fair value, and the cost, if any, to terminate off-balance-sheet financial instruments is not significant.

		(j) Employee Benefits
		The Company recognizes the obligations with its employees in accordance with the current Colombian labor law. These obligations include the severance indemnity and the legal service bonus each one equivalent to a monthly salary per year and interest on severance at the rate of 12% on the balance of severance indemnities paid. The relevant liability for these two concepts is shown under the “Employee benefits” account as current liabilities at the closing of the period.

		(k) Defined Benefit Pension Plan
		The Company has a defined benefit pension plan covering one employee. The benefits are based on years of service, age and the employee’s compensation. Currently, the cost of this program is not being funded. The actuarial study is performed at the end of each year in accordance with the guidelines established by FAS 87.

		(l) Use of Estimates
		The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.

		(m) Revenue Recognition
		The Company recognizes revenue when the crude oil is delivered to Ecopetrol.

		Ecopetrol pays the oil sales invoicing 25% in local currency and the 75% in US Dollars, according to the terms of the Oil Sales Contract executed between Ecopetrol and Argosy, through which the oil sale price is fixed, with expiration dated November 1, 2006.

		(n) Management Fee
		The Company accounts for the management fees received from its partners as operator of the contracts as a less value of the operating costs.

	(o) Comprehensive Income
	For each period presented in the accompanying statements of income, comprehensive income and net income are the same amount.

(3)	Cash and Cash Equivalents

	The following is a summary of cash and cash equivalents as of March 31, 2006 and December 31, 2005:

	March 31,		December 31,
	2006		2005
Held in United States dollars	$	2,040		6,329
Held in Colombian pesos		157		394
Short-term investments		473		401
	$	2,670		7,124

(4)	Accounts Receivable

	The following is a summary of accounts receivable as of March 31, 2006 and December 31, 2005:


	March 31,			December 31,
	2006			2005
Trade	$	3,248			675
B.T.O. Río Magdalena Agreement		355			355
Vendor Advances		177			172
Petroleum Equipment Investments - Talora		300			—
Other		173			104
		4,253			1,306
Less allowance for bad debts		(355	)		(355	)
	$	3,898			951

(5)	Property, Plant and Equipment

	The following is a summary of property, plant and equipment as of March 31, 2006 and December 31, 2005:

	March 31,		December 31,
	2006		2005
Oil properties:
Unproved	$	3,831		3,622
Proved		59,190		59,096
		63,021		62,718
Less accumulated depreciation, depletion, and amortization		53,885		53,695
	$	9,136		9,023

Excluded From the Capitalized Cost Being Amortized

Capitalized Cost Unproved

															Month
															Anticipated
															to be
															included
			Exploration Cost						Cost Incurred						in
AFE	Contract	Detail	Dec-04		Dec-05		Mar-06		2004		2005		2006		Amortization
MARY WELLWEST PROSPECT	Santana	Geological & Geophysical Data		287		287		287		287					Dec-06
MARY WEST WELL TESTING	Santana	Geological & Geophysical Data		93		93		93		93					Dec-06
Expl. 100% NEW PROJECTS	New Projects	Geological & Geophysical Data		253		363		375		253		110		12	Dec-06
Expl. 100% SANTANA	Guayuyaco	Geological & Geophysical Data		1,044		1,044		1,044		1,044					Dec-06
Expl. 100% RIO MAGDALENA	Rio Magdalena	Seismic Program		634		808		889		634		174		81	Mar-07
TALORA PROJECT	Talora	Seismic Program		1		89		134		1		88		44	Sep-07
SEISMIC GUAYUYACO	Guayuyaco	Seismic Program		0		431		431				431			Dec-06
SEISMIC CHAZA	Chaza	Seismic Program		0		505		538				505		33	Sep-07
POPA-1 WELL EXPLORATORY	Rio Magdalena	Road and Location Well		0		0		32						32	Mar-07
JUANAMBU-1 WELL EXPLORATORY	Guayuyaco	Road and Location Well		0		2		8				2		6	Jun-07
						0		0
Total Unproved Exploration Costs				2,312		3,622		3,831		2,312		1,310		208

All capital excluded from capital costs being amortized relates to exploration cost. No acquisition costs, development costs or capitalized interest costs are identified.

(6)		Pension Plan

		The following is a detail of the components of pension cost as of March 31, 2006 and 2005:

	March 31,			March 31,
	2006			2005
Interest cost	$	8			8
Expected return of assets		(13	)		(6	)
Amortization of unrecognized net transition obligation (asset)		1			1
Net periodic pension cost	$	(4	)		3

(7)		Equity

		Stockholders’ Capital

		The following is a detail of the stockholders’ participation in the capital as of March 31, 2006 and December 31, 2005:

	March 31,		December 31,
Stockholder	2006		2005
Crosby Capital L.L.C.	$	98.75		98.75
Argosy Energy Corp. **		0.71		0.71
Dale E. Armstrong		0.41		0.41
Richard S. McKnight		0.13		0.13
	$	100.0		100.00


**		Argosy Energy Corp. is a general partner interest. All others are limited partnership interests. Net income is allocated according to the participation of each stockholder in the Company’s capital.

		Foreign Exchange Restrictions

		In accordance with current legislation in Colombia, the branches of foreign companies in the oil industry are not under the obligation to refund to the Colombian exchange market the proceeds from their foreign currency sales either inside or outside the country. The net proceeds from oil exports may be used by the branches of oil companies to reimburse abroad the capital and profits from the operation in Colombia. As a result of this foreign exchange liberation, the branch cannot purchase foreign currency in the Colombian exchange market to remit profits, repatriate capital, repay external debt or pay foreign currency expenses.

		Distributions to Partners

		On March 30, 2006 the partners of Argosy Energy International resolved, with the majority vote of its partners, distribute the amount of $2,500 on March 1, 2006 and $750 on March 30, 2006, ratably to each of its partners.

(8)		Operating Cost

		The following is a summary of operating cost incurred for the period ended March 31, 2006 and 2005:

	March 31,		March 31,
	2006		2005
Direct labor	$	111		86
Maintenance, materials and lubricants		86		49
Repairs - third party		123		196
General expenses - other		47		33
	$	367		364

(9)		Income Taxes

		All of the income and income tax was derived from activities of the Branch in Colombia.

		Deferred Remittance Tax
		Deferred remittance tax is calculated based upon commercial net income. Commercial net income of Colombian branches of foreign companies derived from exploration, development or production of hydrocarbons is levied an additional remittance tax of 7%.

		The law establishes that when this income is reinvested in the country for five years, the payment of the remittance tax will be deferred, after which time the payment of this tax will be exonerated.

		Under the law, reinvestment occurs when the net income remains five years within the equity of the entity.

		Tax Reconciliation

		Income tax expense attributable to income from continuing operations was $1,126 and $412 for the periods ended March 31, 2006 and 2005, and differed from the amounts computed by applying the Colombian income tax rate of 35% (the statutory tax rate of the partnership’s Branch) to pretax income from continuing operations as a result of the following:

	March 31, 2006				March 31, 2005
	Amount		%		Amount		%
Income before taxes	$	2,815		100.00		1,045		100.00
Computed “Expected” tax expense		985		35.00		366		35.00
Tax expense		1,126		40.00		412		39.43
Difference	$	141		5.00		46		4.43

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and tax carryforwards utilizable. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the branch will realize the benefits of these deductible differences, net of the existing valuation allowances at March 31, 2006. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

				March 31, 2006									March 31, 2005
	Basis			Amount			%			Basis			Amount			%
Explanation:
Difference in principles and translation	$	(312	)		(109	)		(3.88	)		(86	)		(30	)		(2.87	)
Surcharge tax (10%)					92			3.28						34			3.25
Remitance tax expense (7%)					146			5.19						42			4.02
Inflation adjustment		(23	)		(8	)		(0.28	)					—			—
No deductible expenses		9			3			0.11						—			—
No deductible taxes (Industry and commerce, stamp tax)		41			14			0.51						—			—
Assessments to financial movements		6			2			0.07						—			—
Income not taxable		4			1			0.00						—
	$				141			5.00						46			4.43

The deferred tax is originated in the following temporary differences as of March 31, 2006 and December 31, 2005:

	March 31,			December 31,
	2006			2005
Accrued liabilities	$	201			201
Property, plant and equipment		(674	)		(676	)
Net deferred tax liability	$	(473	)		(475	)

Roll forward of deferred taxes:
Beginning balance		475			223
Increase in year		—			352
Translation		(2	)		(100	)
	$	473			475

Major Changes Introduced by Law 863 (December 29, 2003)

	1)		An equity tax was created for fiscal years 2004, 2005 and 2006. Such tax must be liquidated applying at 0.3 % over the net equity at January 1^st of each year. This applies to equities of 3.000 million pesos in 2004, 3.183 million pesos in 2005 and 3.344 million pesos in 2006.

	2)		The financial transaction tax increased from 3 per thousand to 4 per thousand and it is applicable through the year 2007.

	3)		Paid taxes are not deductible except for 80% of industrial and commercial and Property Taxes.

	4)		The 10% income tax surcharge (3.5%) is applicable for years 2003 through 2006. This payment is not deductible for tax purposes.

(10)		Settlement Agreement with Aviva Overseas Inc.

		Effective August 19, 2005 Argosy Energy International, LP, Argosy Energy Corp., Crosby Capital, LLC, and Aviva Overseas, Inc. entered into a settlement agreement which principal terms are as follows:

	1.		The parties agreed that the agreement is a negotiated resolution of various disputes between the parties.

	2.		Aviva Overseas, Inc. assigned and transferred all interests in the partnership, corresponding to 29.6196%, to Argosy Energy International, LP as a redemption of such interests.

	3.		Argosy Energy International, LP is required to make the following payments to Aviva Overseas, Inc.: an initial cash payment of $300 as reimbursement to Aviva Overseas, Inc. for a portion of its cost incurred in connection with the disputes, a 90 day promissory note amounted to $3,050, a two year promissory note in the amount of $1,125 (the “Note”, represented for 8 quarterly payments of $153 beginning in November 2005, including interest at 8%), and an additional payment (described below) accrued in the amount of $329 as of the agreement date. As of March 31, 2006, amounts outstanding under the agreement include $990 due on the Note and $310 accrued for the additional payment. The outstanding amount is payable as follows: $614 in 2006 and $686 in 2007.

The additional payment is calculated as follows: after the earlier of i) The date Argosy Energy makes final payment of the “Note”, or (ii) after the occurrence of an event of default, Argosy shall make a payment in cash in an amount equal to (i) $56,250 multiplied by the numeric amount by which the average daily closing price of the New York Mercantile Exchange nearby month contract for West Texas Intermediate crude oil over the note term exceeds $55 per barrel, reduced by (ii) all interest paid by Argosy on the principal of the Note. The additional payment was recorded at the date of the settlement agreement based on a calculation of the required payment at that date.

Crosby Capital, LLC has guaranteed the payments required by Argosy Energy International, LP.

The new ownership percentages in Argosy Energy International L.P., after the redemption of the partnership interest held by Aviva Overseas Inc. are as follows:

				Type of
Partner	Interest			interest
Crosby Capital L.L.C.		98.7491	%	Limited Partner
Argosy Energy Corporation		0.7104	%	General Partner
Dale E. Armstrong		0.4122	%	Limited Partner
Richard S. McKnight		0.1283	%	Limited Partner
Total		100.0000	%

(11)		Disagreement Between Argosy Energy International and Ecopetrol

		As of March 31, 2006 the contracting parties of Guayuyaco Association Contract, Ecopetrol and Argosy Energy International, consulted with their legal advisors to clarify the procedure for allocation of oil produced and sold during the long term test of the Guayuyaco-1 and Guayuyaco-2 wells. Ecopetrol has advised Argosy of a material difference in the interpretation of the procedure established in the Clause 3.5 of Attachment-B of the Guayuyaco association Contract. Ecopetrol interprets the contract to provide that the extend test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back in to the Guayuyaco discovery. Argosy’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for benefit of Ecopetrol. While Argosy believes its interpretation of the Guayuyaco Association Contract is correct, the resolution of this issue is still pending of agreement between the parties or determination through legal proceedings.

		The estimated value of disputed production is $2,361,188 which possible loss is shared 50% ($1,180,594) with Solana Petroleum Exploration (Colombia) S.A. partner in the contract and 50% Argosy.

		At this time no amount has been accrued in the financial statements.

(12)		Subsequent Events

•

The Company signed in May and June, 2006 two new exploration and production contracts with the National Hydrocarbons Agency (ANH) called Primavera and Mecaya, to explore and produce oil, respectively.

		These contracts have a maximum duration of 30 years with an exploration period of 6 years and a production period of 24 years, which starts upon the date in which Argosy receives the oil field commerciality declaration from ANH.

		The contracts may be relinquished at the end of each phase after fulfillment of the agreed obligations.

	•		On April 1, 2006 the partners of the partnership entered into a redemption agreement pursuant to which all of Dale E. Armstrong interest and Richard S. McKnight interest.

	•		On June 21, 2006 Gran Tierra Energy Inc. acquired all of the outstanding partnership interest in the Company.

December 31, 2005 and 2004

Financial Statements

With Independent Auditors’ Report Thereon

INDEPENDENT AUDITORS’ REPORT

Partners of

Argosy Energy International, LP:

We have audited the accompanying balance sheets of Argosy Energy International, LP as of December 31, 2005 and 2004, and the related statements of income, partner’s equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Argosy Energy International, LP as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

Years ended December 31, 2005 and 2004

Statements of Income

	2005		2004
Oil sales to Ecopetrol	$	11,891		6,393
Operating cost (note 9)		2,452		2,060
Depreciation, depletion and amortization		697		357
General and administrative expenses		1,082		859

		4,231		3,276

Operating profit		7,660		3,117

Other income, net (note 10)		449		225

Income before income and remittance taxes		8,109		3,342

Current income tax (note 11)		2,187		1,026
Deferred income tax		352		245
Deferred remittance tax		353		146
Total income and remittance taxes		2,892		1,417
Net Income	$	5,217		1,925

December 31, 2005 and 2004

Balance Sheets

	2005		2004
Assets
Current assets:
Cash and cash equivalents (note 3)	$	7,124		6,954
Accounts receivable, net (note 4)		951		584
Accounts receivable reimbursement Ecopetrol		1,186		—
Inventories:
Crude oil		218		154
Materials		557		248
		775		402
Total current assets		10,036		7,940

Other long-term assets		16		10
Property, plant and equipment (note 5):
Unproved properties		3,622		2,312
Proved properties, net		5,401		3,211
		9,023		5,523
Total assets	$	19,075		13,473

Liabilities and Partners’ Equity

Current liabilities:
Accounts payable		4,979		1,745
Tax payable		1,326		826
Employee benefits		103		88
Accrued liabilities		522		375
Total current liabilities		6,930		3,034

Long-term accounts payable (note 6)		686		—
Deferred income tax		475		223
Deferred remmittance tax		1,104		714
Pension plan (note 7)		—		35
Total liabilities		9,195		4,006
Partners’ equity (note 8)		9,880		9,467
Total liabilities and Partners’ equity	$	19,075		13,473

Years ended December 31, 2005 and 2004

Statements of Cash Flows

	2005			2004
Cash flows from operating activities:
Net income	$	5,217			1,925
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		697			357
Bad debt allowance		116			239
Deferred income tax		352			245
Deferred remittance tax		353			146
Pensions		24			59
Changes in assets and liabilities:
Accounts receivable		(1,669	)		(191	)
Inventories		(373	)		339
Accounts payable		2,620			1,245
Tax payable		500			716
Employee benefits		15			28
Accrued liabilities		147			102
Deferred income tax		(100	)		(4	)
Deferred remmittance tax		37			58

Net cash provided by operating activities		7,936			5,264

Cash flows from investing activities:
Increase in long term investments		(65	)		(70	)
Additions to property, plant and equipment		(4,197	)		(748	)

Net cash used in investing activities		(4,262	)		(818	)

Cash flows used in financial activities - Redemption of partnership interest - Aviva Overseas Inc.		(3,504	)		—

Net increase in cash and cash equivalents		170			4,446
Cash and cash equivalents at beginning of year		6,954			2,508

Cash and cash equivalents at end of year	$	7,124			6,954

Statements of Partners’ Equity

Years ended December 31, 2005 and 2004

	Limited			General			Total
	partners’			partners’			partners’
	capital			capital			equity
Balance as of December 31, 2003	$	7,504			38			7,542

Net income		1,915			10			1,925

Balance as of December 31, 2004		9,419			48			9,467

Net income		5,180			37			5,217

Redemption of partnership interest -
Aviva Overseas Inc. (note 6)		(4,789	)		(15	)		(4,804	)
Balance as of December 31, 2005	$	9,810			70			9,880

December 31, 2005 and 2004

Argosy Energy International, LP is a Utah (USA) Limited Partnership, which established a Colombian Branch in 1983.

(1) Business Activities

Argosy Energy International, LP is engaged in the business of exploring for, developing and producing oil and gas. The principal properties and operations are located in Colombia, which are carried out through its Colombian Branch in the Putumayo, Cauca, Tolima and Cundinamarca Provinces. The oil production is sold to Empresa Colombiana de Petróleos, the Colombian National Oil Company, (“Ecopetrol”).

There are risks involved in conducting oil and gas activities in remote, rugged and primitive regions of Colombia. The guerrillas have operated within Colombia for many years and expose the Company’s operations to potentially detrimental activities. The guerrillas are present in the Putumayo and Río Magdalena areas where the Company’s properties are located. Since 1998, the Company has only experienced minor attacks on pipelines and equipment.

Operations

As of December 31, 2005, Argosy was participating in the following Association Contracts signed with Ecopetrol and Exploration and Exploitation Contracts signed with the Hydrocarbons National Agency - ANH.

Contract

Participation

Operator

Phase

Santana

ARGOSY

Exploitation

Guayuyaco

ARGOSY

Exploitation

Aporte Putumayo

100

ARGOSY

Abandonment

Río Magdalena

ARGOSY

Exploration

Talora

ARGOSY

Exploration

Chaza

ARGOSY

Exploration

The first four contracts have been signed with ECOPETROL and the last two with ANH.

An association contracts are those where the Government participate as partner of the field through the national oil company — ECOPETROL.

Exploration and production contracts (E&P) are those signed with the ANH — “Agencia Nacional de Hidrocarburos” (National Agency for Hydrocarbons) in which the Government only receive royalties and taxes for the rights of exploration and production but there is not a participation from the national oil company - ECOPETROL or any other government entity.

The main terms of the above-mentioned contracts are as follows:

Santana Association Contract

On May 27, 1987 (effective date July 27, 1987), Argosy Energy International, LP signed this association contract to explore for and produce oil, in the area called Santana. The contract is in its 19th year and the Company reduced the area to a 5 kilometer reserve area around each field. The remaining contract area is approximately 1,100 acres.

Under the terms of the contract with Ecopetrol, a minimum of 25% of all revenues from oil sold to Ecopetrol is paid in Colombian pesos, which may only be utilized in Colombia. However, this proportion can be modified through parties agreement.

Aporte Putumayo - Association Contract

The Aporte Putumayo area has been returned to the Government. Such devolution is subject to the approval of the environmental restoration of the region by the Ministry of Environment and the treatment of the abandonment of the wells agreed with Ecopetrol and the Ministry of Mines.

Río Magdalena Association Contract

On December 10, 2001 (effective date February 8, 2002), Argosy Energy International, LP and Ecopetrol signed this Association Contract, to explore and produce oil, in the area called Río Magdalena of approximately 145,000 acres, located in the Middle Magdalena region of Colombia in the provinces of Cundinamarca and Tolima.

The contract has a maximum duration of 28 years distributed as follows: an exploration period of 6 years and a production period of 22 years starting on the date of termination of the exploration period. The exploratory well, Popa-1 was drilled during June and July and is on the completion stage.

Upon finalization of each phase, Argosy has the option to cancel the contract having previously completed the obligations agreed for each phase.

BT Letter Agreement

On February 27, 2001 Argosy Energy International, LP signed a letter agreement with BT Operating Company for the acquisition and management of the Río Magdalena Exploration Area. BT and Argosy mutually agreed to pay their 50% share of costs under the terms of the Ecopetrol Association contract and provide certain services toward management and compliance of the obligations. As of December 31, 2005 BT had not met their obligations under this agreement and outstanding accounts receivable of $355 related to their share of costs related to the Río Magdalena Association Contract were provisioned as bad debts.

On August 2, 2002 (effective date September 30, 2002) Argosy Energy International, LP signed this association contract with Ecopetrol, to explore and produce oil, in the area named Guayuyaco. This Association contract gives Argosy the right to explore potential reserves in prospects adjacent to the existing Santana oil field. The block is located in the Putumayo and Cauca provinces and covers approximately 52.000 acres originally held under the Santana Risk Sharing Agreement.

Guayuyaco Association Contract

The Guayuyaco contract has a maximum duration of 27.5 years with an exploration period of 5.5 years and a production period of 22 years, which starts upon termination of the exploration period.

Argosy has the obligation of carry out the exploration work in two phases, which were completed. In the first phase, the Branch drilled the Inchiyaco -1 exploration well which was successful. During the second exploration phase, two wells were drilled, Guayuyaco-1 and Guayuyaco-2, which were successful. Therefore, on December 28, 2005, Ecopetrol accepted the Commerciality of the field.

Solana Petroleum Exploration Commercial Agreement

Argosy and Solana Petroleum Exploration entered into a commercial agreement in 2003 whereby, Solana through fulfillment of certain obligations could earn a participating interest in the Inchiyaco Prospect and have an option to enter the next exploration prospect under the Guayuyaco Association Contract. Inchiyaco-1 was drilled and completed as a producing well in 2003 resulting in Solana’s sharing 26.21% interest in Argosy’s net share of the prospect.

The commercial agreement was revised in 2004, giving Solana the right to share a 50% interest in Argosy’s net share of the Guayuyaco association contract by paying 66.7% of two exploratory wells (Guayuyaco-1 and Juanambu-1) and 50% for a new seismic program and additional projects.

Talora Exploration and Exploitation Contract

On September 16, 2004, (effective date), Argosy and the National Hydrocarbons Agency (ANH) signed the Talora exploration and exploitation contract to explore and produce oil, in an area of approximately 108,000 acres located in Tolima and Cundinamarca Provinces.

The contract has a maximum duration of 30 years with an exploration period of 6 years and a production period of 24 years, which starts upon the date in which Argosy receives the oil field commerciality declaration from ANH.

The contract may be relinquished at the end of each phase after fulfillment of the agreed obligations.

Contractual Commitments:

	Starting
Phase	date	Obligations
3	December 16, 2006	One exploratory well.
4	December 16, 2007	One exploratory well.
5	December 16, 2008	One exploratory well.
6	December 16, 2009	One exploratory well.

Chaza Exploration and Exploitation Contract

On June 27, 2005 (effective date) Argosy and the National Hydrocarbons Agency (ANH) signed the Chaza exploration and exploitation contract to explore and produce oil, in an area of approximately 80,000 acres located in Putumayo and Cauca Provinces.

The ANH Resolution 0217, dated September 13, 2005, approved the 2005 assignment of 50% interest of the contract to Solana Petroleum Exploration.

Contractual Commitments:


	Starting
Phase	date	Obligations
2	June 27, 2006	One exploratory well.
3	June 27, 2007	One exploratory well.
4	December 16, 2008	One exploratory well.
5	December 16, 2009	One exploratory well.
6	December 16, 2010	One exploratory well.

The contract may be relinquished at the end of each phase after fulfillment of the agreed obligations.

The transactions and accounts of the Company’s operations denominated in currencies other than US dollars are re-measured into United States dollars in accordance with Statement of Financial Accounting Standards FAS 52. The United States dollar is used as the functional currency. Exchange adjustments resulting from foreign currency balances are recognized in expense or income in the current period.

(2) Summary of Significant Accounting Policies and Practices

(a) Foreign Currency Translation

(b) Cash Equivalents

Cash equivalents are highly liquid investments purchased with an original maturity of three months or less.

(c) Inventories

Inventories consist of crude oil and materials and supplies and are stated at the lower of cost or market.

(d) Property, Plant and Equipment

The Company follows the full cost method to account for exploration and development of oil and gas reserves whereby all productive and nonproductive costs are capitalized. The only cost center is Colombia. All capitalized costs plus the undiscounted future development costs of proved reserves are depleted using the unit of production method based on total proved reserves applicable to the country.

Proved oil and gas reserves are the estimated quantities of crude oil that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions considering future production and development costs.

While the quantities of proved reserves require substantial judgment, the associated prices of oil reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of prices and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.

Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a country.

Support equipment and facilities are depreciated using the unit of production method based on total reserves of the field related to the support equipment and facilities.

(e) Environmental Liabilities and Expenditures

Argosy accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.

(f) Asset Retirement Obligations

Liability for asset retirement obligation is considered to be negligible at this time, based on projected production profiles, expiry dates and terms of the Association Contracts for current operations. However, the Company has accrued the costs related to environmental remediation and abandonment of the wells belonging to Aporte Putumayo Contract.

(g) Concentration of Credit Risks

All of the company’s production is sold to Ecopetrol in which the sale price is agreed between both parts, according to local regulations in Colombia.

(h) Income Taxes

Deferred Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(i) Financial Instruments Fair Value

The carrying amounts of cash and cash equivalents approximate fair value because of the short maturity of those instruments. The carrying value of other on-balance-sheet financial instruments, approximates fair value, and the cost, if any, to terminate off-balance-sheet financial instruments is not significant.

(j) Employee Benefits

The Company recognizes the obligations with its employees in accordance with the current Colombian labor law. These obligations include the severance indemnity and the legal service bonus each one equivalent to a monthly salary per year and interest on severance at the rate of 12% on the balance of severance indemnities paid. The relevant liability for these two concepts is shown under the “Employee benefits” account as current liabilities at the closing of the period.

(k) Defined Benefit Pension Plan

The Company has a defined benefit pension plan covering one employee. The benefits are based on years of service, age and the employee’s compensation. Currently, the cost of this program is not being funded. The actuarial study is performed at the end of each year in accordance with the guidelines established by FAS 87.

(l) Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.

(m) Revenue Recognition

The Company recognizes revenue when the crude oil is delivered to Ecopetrol.

Ecopetrol pays the oil sales invoicing 25% in local currency and the 75% in US Dollars, according to the terms of the Oil Sales Contract executed between Ecopetrol and Argosy, through which the oil sale price is fixed, with expiration dated November 1, 2006.

The Company accounts for the management fees received from its partners as operator of the contracts as a less value of the operating costs.

(n) Management Fee

(o) Comprehensive Income

For each period presented in the accompanying statements of income, comprehensive income and net income are the same amount.

(3) Cash and Cash Equivalents

The following is a summary of cash and cash equivalents as of December 31:

	2005		2004
Held in United States dollars	$	6,329		6,454
Held in Colombian pesos		394		185
Short-term investments		401		315
	$	7,124		6,954

(4) Accounts Receivable

The following is a summary of accounts receivable as of December 31:

	2005			2004
Trade	$	675			81
B.T. Río Magdalena Agreement		355			239
Vendor advances		172			60
Solana joint account		—			324
Other		104			119
		1,306			823
Less allowance for bad debts		(355	)		(239	)
	$	951			584

(5) Property, Plant and Equipment

The following is a summary of property, plant and equipment as of December 31:

	2005		2004
Oil properties:
Unproved	$	3,622		2,312
Proved		59,096		56,218
		62,718		58,530
Less accumulated depreciation, depletion, and amortization		53,695		53,007
	$	9,023		5,523

Excluded From the Capitalized Cost Being Amortized

Capitalized Cost Unproved

Exploration

Cost

Cost Incurred

AFE

Contract

Detail

Dec-04

Dec-05

2004

2005

Amortization

MARY WELLWEST

PROSPECT

Santana

MARY WEST WELL

TESTING

Santana

Geological &

Geophysical Data

Dec-06

EXPL. 100% NEW PROJECTS

New

Projects

EXPL. 100% SANTANA

Guayuyaco

EXPL. 100% RIO MAGDALENA

Rio

Magdalena

TALORA PROJECT

Talora

Seismic Program

Sep-07

SEISMIC GUAYUYACO

Guayuyaco

Seismic Program

431

Dec-06

SEISMIC CHAZA

Chaza

Seismic Program

505

Sep-07

POPA-1 WELL

EXPLORATORY

Rio

Magdalena

Road and Location Well

Mar-07

JUANAMBU-1 WELL

EXPLORATORY

Guayuyaco

Road and Location Well

Jun-07

Total Unproved

Exploration Costs

2,312

3,622

2,312

1,310

All capital excluded from capitalized cost being amortized relates to exploration cost. No acquisition costs, development costs or capitalized interest costs are identified.

(6) Settlement Agreement with Aviva Overseas Inc

Effective August 19, 2005 Argosy Energy International, LP, Argosy Energy Corp., Crosby Capital, LLC, and Aviva Overseas, Inc. entered into a settlement agreement which principal terms are as follows:

1.		The parties agreed that the agreement is a negotiated resolution of various disputes between the parties.

2.		Aviva Overseas, Inc. assigned and transferred all interests in the partnership, corresponding to 29.6196%, to Argosy Energy International, LP as a redemption of such interests.

3.		Argosy Energy International, LP is required to make the following payments to Aviva Overseas, Inc.: an initial cash payment of $300 as reimbursement to Aviva Overseas, Inc. for a portion of its cost incurred in connection with the disputes, a 90 day promissory note amounted to $3,050, a two year promissory note in the amount of $1,125 (the “Note”, represented for 8 quarterly payments of $153 beginning in November 2005, including interest at 8%), and an additional payment (described below) accrued in the amount of $329 as of the agreement date. As of December 31, 2005, amounts outstanding under the agreement include $990 due on the Note and $310 accrued for the additional payment. The outstanding amount is payable as follows: $614 in 2006 and $686 in 2007.

Crosby Capital, LLC has guaranteed the payments required by Argosy Energy International, LP.

The new ownership percentages in Argosy Energy International L.P., after the redemption of the partnership interest held by Aviva Overseas Inc. is as follows:

				Type of
Partner	Interest			interest
Crosby Capital L.L.C.		98.7491	%	Limited Partner
Argosy Energy Corporation		0.7104	%	General Partner
Dale E. Armstrong		0.4122	%	Limited Partner
Richard S. McKnight		0.1283	%	Limited Partner
Total		100.0000	%

(7) Pension Plan

Costs of the retirement plan are accrued based on various assumptions and discount rates, as described below. The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors, which depending on the nature of the changes, could cause increases or decreases in the liabilities accrued.

The components of pension cost as of December 31 are:

	2005			2004
Interest cost	$	34			31
Expected return of assets		(48	)		(30	)
Amortization of unrecognized net transition obligation (asset)		3			3
Net periodic pension cost	$	(11	)		4

Changes in plan assets:
Fund assets at beginning of year		300			232
Interest earned		61			68
Fund assets at end of year	$	361			300

The Company’s fund asset to cover pension benefits is represented in a mutual fund amounting to $361 and $300, in 2005 and 2004, respectively.

	2005			2004
Funded status:
Projected benefit obligation		359			335
Assets at fair value		361			300
Funded status		2			(35	)
Unrecognized net transaction obligation remaining		31			32
Unrecognized prior service cost		—			—
Adjustment additional minimum liability		(2	)		(5	)
Unrecognized net loss or (gain)		(29	)		(27	)
Prepaid (unfunded accrued) pension cost	$	2			(35	)

	2005			2004
Change in benefit obligation
Benefit obligation at beginning of year		335			276
Interest Cost		34			31
Benefits Paid		(24	)		(22	)
Foreign Currency Exchange		14			50
Total Activity		24			59
Benefit obligation at end of year		359			335

The weighted-average assumptions used to determine benefit obligations at December 31 are as follows:

	2005		2004
	%		%
Discount rate		9.3		10.5
Rate of compensation increase		4.7		6.0

Estimated future benefit payments are expected to be paid as follows:


Year	Amount
2006		25
2007		23
2008		22
2009		20
2010		19
2011- 2016		250

No expected contributions will be made to the plan during the year 2006.

The following is a detail of the stockholders’ participation in the capital:

(8) Equity

Stockholders’ Capital

	2005		2004
Stockholders	%		%
Crosby Capital L.L.C.		98.75		69.50
Argosy Energy Corp. **		0.71		0.50
Aviva Overseas, Inc		—		29.62
Dale E. Armstrong		0.41		0.29
Richard S. McKnight		0.13		0.09
		100.00		100.00

** Argosy Energy Corp. is a general partner interest. All others are limited partnership interests. Net income is allocated according to the participation of each stockholder in the Company’s capital.

Foreign Exchange Restrictions

In accordance with current legislation in Colombia, the branches of foreign companies in the oil industry are not under the obligation to refund to the Colombian exchange market the proceeds from their foreign currency sales either inside or outside the country. The net proceeds from oil exports may be used by the branches of oil companies to reimburse abroad the capital and profits from the operation in Colombia. As a result of this foreign exchange liberation, the branch cannot purchase foreign currency in the Colombian exchange market to remit profits, repatriate capital, repay external debt or pay foreign currency expenses.

(9) Operating Cost

The following is a summary of operating cost incurred as of December 31:

	2005		2004
Direct labor	$	383		316
Maintenance, materials and lubricants		417		417
Repairs - third party		700		752
General expenses - others		952		575
	$	2,452		2,060

The following is a summary of other income and expenses, net as of December 31:

(10) Other Income and Expenses, net

	2005			2004
Oil transportation	$	18			146
Financial income		171			65
Insurance reimbursement		126			—
Other income		217			162
Foreign translation gain (loss)		33			(148	)
Allowance for bad debts		(116	)		—
	$	449			225

(11) Income Taxes

All of the income and income tax was derived from activities of the branch in Colombia.

Deferred Remittance Tax

Deferred remittance tax is calculated based upon commercial net income. Commercial net income of Colombian branches of foreign companies derived from exploration, development or production of hydrocarbons is levied an additional remittance tax of 7%.

The law establishes that when this income is reinvested in the country for five years, the payment of the remittance tax will be deferred, after which time the payment of this tax will be exonerated.

Under the law, reinvestment occurs when the net income remains five years within the equity of the entity.

Tax reconciliation

Income tax expense attributable to income from continuing operations was $2,892 and $1,417 for the years ended December 31, 2005 and 2004, respectively, and differed from the amounts computed by applying the Colombian income tax rate of 35% (the statutory tax rate of the partnership’s Branch) to pretax income from continuing operations as a result of the following:

	2005			2004
	Basis Amount %			Basis Amount %
Income before taxes	$	8,109	100.00		3,342	100.00
Computed “Expected” tax expense		2,838	35.00		1,170	35.00
Tax expense		2,892	35.66		1,417	42.40
Difference	$	54	0.66		247	7.40

The deferred tax is the following:

	2005									2004
	Basis			Amount			%			Basis			Amount			%
Explanation:
Difference in principles	$	(593	)		(207	)		(2.56	)		(49	)		(17	)		(0.51	)
Surcharge tax (10%)					199			2.45						93			2.79
Remittance tax expense (7%)					353			4.35						146			4.37
Inflation adjustment		(53	)		(19	)		(0.23	)		(21	)		(7	)		(0.22	)
No deductible expense		32			11			0.14			16			6			0.17
No deductible tax (Stamp tax)		130			46			0.56			57			20			0.60
Assessments to financial movements		45			16			0.19			13			4			0.13
Equity tax		25			9			0.11			31			11			0.33
Deduction fixed real productive assets		(1,014	)		(355	)		(4.38	)
Income not taxable		4			1			0.03			(23	)		(9	)		(0.26	)
	$				54			0.66						247			7.40

	2005			2004
Accrued liabilities	$	201			183
Property, plant and equipment		(676	)		(406	)
Net deferred tax liability	$	(475	)		(223	)

Roll forward of deferred taxes:
Net deferred tax to December 31:
Beginning balance		223			(18	)
Increase in year		352			245
Translation		(100	)		(4	)
	$	475			223

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and tax carryforwards utilizable. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the branch will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2005 and 2004. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

Major Changes Introduced by Law 863 (December 29, 2003)

	1)		An equity tax was created for fiscal years 2004, 2005 and 2006. Such tax must be liquidated applying at 0.3 % over the net equity at January 1^st of each year. This applies to equities of 3.000 millions pesos in 2004, 3.183 millions pesos in 2005 and 3.344 millions pesos in 2006.

	2)		The financial transaction tax increased from 3 per thousand to 4 per thousand and it is applicable through the year 2007.

	3)		Paid taxes are not deductible except for 80% of industrial and commercial and property Taxes.

	4)		The 10% income tax surcharge (3.5%) is applicable for years 2003 through 2006. This payment is not deductible for tax purposes.

(12) Disagreement Between Argosy Energy International and Ecopetrol

As of December 31, 2005 the contracting parties of the Guayuyaco Association Contract, Ecopetrol and Argosy, consulted with their legal advisors to clarify the procedure for allocation of oil produced and sold during the long-term test of the Guayuyaco-1 and Guayuyaco-2 wells. Ecopetrol has advised Argosy of a material difference in the interpretation of the procedure established in Clause 3.5 of Attachment-B to the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Argosy’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for the benefit of Ecopetrol. While Argosy believes its interpretation of the Guayuyaco Association Contract is correct, the resolution of this issue is pending agreement of the parties or determination through legal proceedings. At this time no amount has been accrued in the financial statements as it is not considered probable that a loss will be incurred.

The estimated value of the disputed production is US$2,361,188, which possible loss is shared 50% (US$1,180,594) with the Argosy’s Guayuyaco partner, Solana Petroleum Exploration (Colombia) S.A.

These contracts have a maximum duration of 30 years with an exploration period of 6 years and a production period of 24 years, which starts upon the date in which Argosy receives the oil field commerciality declaration from ANH.

(13)	Subsequent Events

	•	The Company signed in May and June, 2006 two new exploration and production contracts with the National Hydrocarbons Agency (ANH) called Primavera and Mecaya, to explore and produce oil, respectively.

The contracts may be relinquished at the end of each phase after fulfillment of the agreed obligations.

	•		On April 1, 2006 the partners of the partnership entered into a redemption agreement pursuant to which all of Dale E. Armstrong interest and Richard S. McKnight interest.

	•		On June 21, 2006 Gran Tierra Energy Inc. acquired all of the outstanding partnership interest in the Company.

Supplemental Oil and Gas Information (Unaudited)

The following tables set forth Argosy’s net interests in quantities of proved developed and undeveloped reserves of crude oil. Crude oil reserves represent the Argosy-owned oil reserves projected for properties located in Colombia. The reserves are stated after applicable royalties. These estimates include reserves in which Argosy holds an economic interest under production-sharing contracts. The studies to estimated proved oil reserves for the years 2003, 2004 and 2005 were prepared by Huddleston & Co., Inc.

In accordance with SFAS No. 69 and Securities and Exchange Commission (“SEC”) rules and regulations, the following information is presented with regard oil proved reserves, all of which are located in Colombia. These rules require inclusion as a supplement to the basic financial statements a standardized measure of discounted future net cash flows relating to proved oil and gas reserves. The standardized measure, in management’s opinion, should be examined with caution. The bases for these disclosures are independent petroleum engineer’s reserve studies which contains imprecise estimates of quantities and rates of production of reserves. Revision of prior year estimates can have a significant impact on the results. Also, exploration and production improvement costs in one year may significantly change previous estimates of proved reserves and their valuation. Values of unproved properties and anticipated future price, and cost increases or decreases are not considered. Therefore, the standardized measure is not necessarily a “best estimate” of the fair value of oil and gas properties or of future net cash flows.

I-Oil Reserves Information

(In barrels)

Proved Developed and Undeveloped Reserves


Balance at December 31, 2003	1,845,654
Revision of previous estimates	168,766
Improved recovery	—
Purchases of proved reserves	—
Extension and discoveries	—
Production	(197,027	)
Sales	—
Balance at December 31, 2004	1,817,393
Revision of previous estimates	(18,936	)
Improved recovery	—
Purchases of proved reserves	—
Extension and discoveries	822,007
Production	(283,795	)
Sales	—
Balance at December 31, 2005	2,336,669

Proved developed reserves
December 31, 2004	1,817,393
December 31, 2005	2,336,669

II- Capitalized Costs Relating to Oil And Gas Producing Activities

III- Cost Incurred in Oil And Gas Property Acquisition,

	As of December 31,
	2005			2004
Oil & gas properties:
Unproved	$	3,622			2,312
Proved		59,096			56,218
Accumulated depreciation, depletion and amortization		(53,695	)		(53,007	)
Net capitalized costs	$	9,023			5,523

Exploration and Development Activities

IV- Results of operations for producing activities

	For the year ended
	December 31,
	2005		2004
Property acquisitions costs	$	—		—
Exploration costs		1,310		405
Development costs		2,878		45
Costs incurred	$	4,188		450

V- Standardized Measure of Discounted Future Net Cash Flows

	For the year ended
	December 31,
	2005			2004
Revenues - Oil sales	$	11,891			6,393
Production costs		(2,452	)		(2,060	)
Depreciation, depletion and amortization		(697	)		(357	)
Income tax expenses		(2,892	)		(1,417	)
Results of operations	$	5,850			2,559