Page No.
PART I
Item 1.		Business		3
Item 1A.		Risk Factors		8
Item 1B.		Unresolved Staff Comments		19
Item 2.		Properties		19
Item 3.		Legal Proceedings		30
Item 4.		Submission of Matters to a Vote of Security Holders		30
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		32
Item 6.		Selected Financial Data		34
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		51
Item 8.		Financial Statements and Supplementary Data		52
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		78
Item 9A.		Controls and Procedures		78
Item 9A(T)		Controls and Procedures		80
Item 9B.		Other Information		80
PART III
Item 10.		Directors, Executive Officers and Corporate Governance		80
Item 11.		Executive Compensation		80
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		80
Item 13.		Certain Relationships and Related Transactions, and Director Independence		80
Item 14.		Principal Accounting Fees and Services		81
PART IV
Item 15.		Exhibits, Financial Statement Schedules		81
SIGNATURES				82

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This Annual Report on Form 10-K, particularly in Item 1. “Business”, Item 2 “Properties” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). These statements include, but are not limited to, statements concerning our plans, goals, strategies, intent, beliefs or current expectations. Our actual results could differ materially from those projected in the forward-looking statements as a result of a number of factors, risks and uncertainties discussed in this Form 10-K, especially those contained in Item 1A of this Form 10-K. The words “may,” “will,” “could,” “would,” “anticipate,” “expect,” “intend,” “believe,” “continue,” or the negatives of these terms, or other comparable terminology and similar expressions identify these forward-looking statements. The information included herein is given as of the filing date of this Form 10-K with the Securities and Exchange Commission (SEC) and future events or circumstances could differ significantly from these forward-looking statements. Accordingly, we caution readers not to place undue reliance on these statements. Unless required by law, we undertake no obligation to update publicly any forward-looking statements.

 

 

None.

 

 

Offices

We currently lease office space in: Calgary, Alberta; Buenos Aires, Argentina; and Bogota, Colombia. The two Calgary leases expire January 31,  2011 and January 31, 2013 and cost $12,386 per month and $6,684 per month, respectively. Our two Buenos Aires, Argentina leases expire January 31, 2009 and July 15, 2009 and cost $2,117 per month and $2,467 per month, respectively. Of our three Bogota, Colombia leases, two expire in March 31, 2009 and December 2010, respectively, and one expired on February 29, 2008, with costs of $794, $30,321 and $2,774 per month respectively. The expired lease will not be replaced, as the space is replaced by the lease that expires December 2010. The properties remaining on lease are in excellent condition, and we believe that they are sufficient for our office needs for the foreseeable future.

 

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Oil and Gas Properties-Colombia

In June 2006, we purchased Argosy Energy International L.P (“Argosy”) which was subsequently renamed Gran Tierra Energy Colombia Ltd. Argosy had interests in seven Exploration and Production contracts at that time, including Santana, Guayuyaco, Chaza and Mecaya in the Putumayo basin; Talora and Rio Magdalena in the Magdalena basin; and Primavera in the Llanos basin. The acquisition price included overriding royalty rights and net profits interests in the blocks that were owned by Argosy at the time of the acquisition. The Azar block in the Putumayo basin was acquired later in 2006, and the Putumayo Technical Evaluation Areas in the Putumayo basin were acquired in 2007. We relinquished the Primavera block in 2007.

 

Currently, the Guayuyaco, Santana and Chaza blocks are producing oil. Oil prices are defined by contract and are related to a WTI reference price. By contract, 25% of sales are denominated in Colombian pesos and 75% in US dollars. Oil is sold to Ecopetrol and is exported via the Trans-Andean pipeline.

 

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Santana

The Santana block covers 1,119 acres and includes 15 producing wells in 4 fields — Linda, Mary, Miraflor and Toroyaco. Activities are governed by terms of a Shared Risk Contract with Ecopetrol, and we are the operator. The properties are subject to a 20% royalty and we hold a 35% interest in all fields with the exception of one well located in the Mary field, Inchiyaco, where we hold a 25.83% working interest, and a third party holds a 9.17% interest. Ecopetrol holds the remaining interest. The block has been producing since 1991. Under the Shared Risk Contract, Ecopetrol initially backed in to a 50% interest upon declaration of commerciality in 1991. In June 1996, when the field reached 7 million barrels of oil produced, Ecopetrol had the right to back into a further 15%, which it took, for a total ownership of 65%.

 

The production contract expires in 2015, at which time the property will be returned to the government. As a result, there will be no reclamation costs.

 

In 2007, we performed remedial work on various wells and upgraded the Mary field water processing facility. For 2008, we will continue with regular field maintenance.

 

Guayuyaco

 

The Guayuyaco block covers 52,366 acres and includes the area surrounding the four producing fields of the Santana contract area. The Guayuyaco block is governed by an Association Contract with Ecopetrol, resulting in a base royalty of 8%, for production of less than 5,000 barrels of oil per day. The royalty increases in a linear fashion to 20% for production between 5,000 and 125,000 barrels of oil per day, and is stable at 20% up to production of 400,000 barrels of oil per day. For production between 400,000 and 600,000 barrels of oil per day the rate increases again to a maximum of 25%. We are the operator and have a 35% participation interest, and our partners are a third party (35%) and Ecopetrol (30%). The Guayuyaco field was discovered in 2005. Two wells are now producing, with Guayuyaco-1 commencing production in February 2005 and Guayuyaco-2 beginning production in September 2005. A combined 2D and 3D seismic survey was acquired over the block in 2005. Ecopetrol may back-in to a 30% participation interest in any new discoveries in the block.

 

The contract expires in two phases: the exploration phase and the production phase. The exploration phase expired in 2005 and the production phase expires in 2027. We have completed all of our obligations in relation to the exploration phase of the contract. In March 2007, we completed drilling the Juanambu-1 exploration well and testing was completed in May 2007. Pre-commercial production began in June 2007. Ecopetrol has backed-in with a 30% participation in the discovery, leaving us with a 35% participation interest. Commerciality was granted by Ecopetrol on November 8, 2007. The property will be returned to the government upon expiration of the production contract. As a result, there will be no reclamation costs.

 

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In 2008 we plan to drill a second well on the Juanambu discovery, as well as upgrade facilities and acquire 20 kilometers of 3D seismic, which also extends into the Chaza block.

 

Rio Magdalena

 

Argosy entered into the Rio Magdalena Association Contract with Ecopetrol in February 2002. The Rio Magdalena block covers 144,670 acres and is located approximately 75 kilometers west of Bogota, Colombia. This is an exploration block and there are no reserves at this time. We are the operator of the block. According to the terms of the exploration contract, we were committed to drill three exploration wells prior to February 2008. The first of these wells, Popa-1, was drilled in late 2006 and was subsequently plugged and abandoned after testing oil production at non-commercial rates (60 barrels per day). The drilling for the second exploration well, Caneyes-1, began in late December 2006 and the well was subsequently plugged and abandoned in February 2007. We have entered the final exploration phase, which expired February 7, 2008. The contract provides for a 60 day grace period from the date of expiry of the exploration phase in order to remedy any incomplete work commitments. One additional exploration well is planned in satisfaction of our commitment for the final exploration phase The production contract expires in 2030 at which time the property will be returned to the government. As a result, there will be no reclamation costs.

 

We entered into a commercial agreement with a third party on January 9, 2008 whereby the third party will fund 100% of the additional exploration well, to earn a 60% working interest in the block. The third party will only earn their 60% interest once the obligation to fully fund the exploration well is completed. We will remain operator of the property.

 

According to the terms of the Association Contract, Ecopetrol may back-in for a 30% participation upon commercialization, and a sliding scale royalty will apply. The base royalty rate is currently 8%, for production less than 5,000 barrels of oil per day, and follows the same sliding scale progression as the Guayuyaco block royalty rates.

 

Chaza

 

The Chaza block covers 80,242 acres and is governed by the terms of an Exploration and Exploitation Contract with the government agency ANH. We are the operator and hold a 50% participation interest. The discovery of the Costayaco field in the Chaza Block was the result of drilling the Costayaco-1 exploration well in the second quarter of 2007. This well commenced production in July, 2007. We completed drilling the Costayaco-2 development well on January 2, 2008, and completed casing on January 8, 2008. This well encountered the same reservoir sequences with similar good oil and gas shows as Costayaco-1. Testing of the Costayaco-2 well was completed in February, 2008 and the well bore is currently being completed for production. We commenced drilling Costayaco-3 in January 2008, and completed drilling on February 20, 2008. Costayaco-3 is currently being tested. Four further development wells are planned for 2008, along with facilities and pipeline expansion and 20 kilometers of 3D seismic, which is an extension of the 3D seismic planned for the Guayuyaco block.

 

The contract for this field expires in two phases. The exploration phase expires in 2011 and the production phase ends in 2032. The property will be returned to the government upon expiration of the production contract. Within sixty days following the date of the return of the property, we must carry out an abandonment program to the satisfaction of ANH. In conjunction with the abandonment, we must establish and maintain an abandonment fund to ensure that financial resources are available at the end of the contract. The base royalty rate is currently 8%, for production less than 5,000 barrels of oil per day, and follows the same sliding scale progression as the Guayuyaco block royalty rates.

 

Talora

 

We currently hold a 20% working interest and are the operator for the Talora block. The Exploration and Exploitation Contract associated with the block was originally signed in September 2004, providing for a six year exploration period and 24 year production period. The Talora contract area covers 108,334 acres and is located approximately 75 kilometers west of Bogota, Colombia. This is an exploration block and there are currently no reserves. We commenced drilling the Laura-1 exploration well on December 27, 2006, at no cost to us, and it was subsequently plugged and abandoned in January 2007. Drilling of this well has fulfilled our commitment for the second exploration phase of the contract, which ended December 15, 2006, and which contained a 60 day grace period to remedy incomplete work commitments. The third exploration phase has begun and we have a commitment to drill one well. We entered into a commercial agreement with a third party on December 27, 2007, whereby the third party will pay 100% of our 20% interest in the next exploration well drilled on Talora, in 2008. Once this obligation is fulfilled, we will apply to ANH to have our entire 20% interest in the Talora block assigned to the third party. The property will be returned to the government upon expiration of the production contract.

 

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Primavera

 

The Primavera Exploration and Exploitation contract was signed May 2006. The Primavera contract area covers 359,064 acres in the Llanos basin. We were the operator and had a 15% participation interest. Chaco Resources also had a 55% participation interest. In 2007, we drilled two wells in the Primavera area at no cost to us. Both wells were dry and were plugged and abandoned. Along with our partners in the field, we decided to relinquish the contract. We have no further obligations in relation to this contract.

 

Mecaya

 

The Mecaya Exploration and Exploitation contract was signed June 2006. The Mecaya contract area covers 74,128 acres in southern Colombia, about 150 kilometers southeast of Pasto. We are the operator and currently have a 15% participation interest. The first phase was scheduled to expire June 2007; however, we received a 6 months extension due to extensive consultation required with the local indigenous population. We are currently applying to ANH to have the period extended again, as guerilla activities in the area have prevented us from meeting exploration commitments by the new December, 2007 deadline. On December 27, 2007, we entered into a commercial agreement with a third party whereby the third party will pay us $1,475,000 upon our receipt of an extended work term for the first phase of exploration. Once payment has been received, we will apply to ANH to have our entire 15% interest assigned to the third party. Work plans include 2-D seismic and reprocessing, road construction, plus re-completion of the existing Mecaya-1 well bore. Seismic acquisition began in mid February, 2008. Phase two of the exploration contract expires in 2010. The exploitation phase for this contract expires 24 years after commerciality is approved. The property will be returned to the government upon expiration of the production contract.

 

Azar

 

We acquired an 80% interest in the Azar property through a farm-in in late 2006, and were obliged to pay the original owner’s 20% share of future costs, as well as our own 80% share. In mid-2007 we farmed out 50% of our interest to a third party. The third party will pay 100% of our 80% share of exploration and development costs for the first three phases of the exploration contract, and we are obliged to pay 20% of costs under our farm-in agreement. This exploration block covers 51,639 acres. We acquired 40 square kilometers of 3-D seismic at the end of 2007 and beginning of 2008 to assess exploitation opportunities. In 2008 we will drill one well on the property. The exploration contract expires in 2012 for this property. The exploitation phase expires 24 years after commerciality is approved. The property will be returned to the government upon expiration of the production contract. If we make a commercial discovery on the block, and produce oil, we will be obligated to perform abandonment activities, under the same conditions as those for the Chaza block.

 

Putumayo A&B Technical Evaluation Areas

 

We were awarded two Technical Evaluation Areas in the Putumayo Basin in southern Colombia in June 2007. The two Technical Evaluation Areas are located near the Orito Field, the largest oil field in the Putumayo Basin.

 

Putumayo West A covers an area of 230,671 hectares (570,000acres) and is held 100% by Gran Tierra. The evaluation period is 12 months, expiring August 28, 2008. During this time, we have an obligation to conduct 400 kilometres of seismic reprocessing and geologic studies. We will have a preferential right to apply for an Exploration and Exploitation contract in the area during the evaluation stage and match or improve any bid by third parties to convert all or a portion of the Technical Evaluation Area to an exploration license.

 

Putumayo West B covers an area of 44,111 hectares (109,000 acres) and is held 100% by Gran Tierra. The evaluation period is for 11 months. During this time, we have an obligation to conduct 100 kilometres of seismic reprocessing and geologic studies. We have begun negotiations to convert this Technical Evaluation Agreement to an Exploration and Exploitation contract in the area. If negotiations are successful, the Technical Evaluation Area will be converted to an Exploration and Exploitation contract through the ANH, and the retained acreage would be subject to the new ANH royalty/tax terms which include no additional state participation.

 

Oil and Gas Properties-Argentina

In September 2005, we entered Argentina through the acquisition of a 14% interest in the Palmar Largo joint venture, and a 50% interest in each of the Nacatimbay and Ipaguazu blocks. In 2006, we purchased further properties in Argentina, including the remaining 50% interest in Nacatimbay and Ipaguzau, a 50% interest in El Vinalar and 100% interests in El Chivil, Valle Morado, Surubi and Santa Victoria. Our Argentina properties are located in the Noroeste Basin in northern Argentina.

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Palmar Largo

 

The Palmar Largo joint venture block encompasses 341,500 acres. This asset is comprised of several producing oil fields in the Noroeste Basin of northern Argentina. We own a 14% working interest in the Palmar Largo joint venture, which we purchased in September 2005. A total of 14 gross wells are currently producing. We produce good quality light oil from this field.

 

An exploration well was drilled in late 2005 but did not indicate commercial quantities of oil. A portion of the drilling costs for this well was factored into our purchase price for Palmar Largo. Drilling on the Ramon Lista-1001 well was completed in December 2005. Production from the well began in early February 2006 at 299 barrels per day (gross after 12% royalty) or 42 barrels per day net to us. No additional wells were drilled in the area during 2006.

 

The Palmar Largo block rights expire in 2017 but provide for a ten-year extension. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government.

 

Our work program for 2008 involves optimization of well performance and operating expenses to maximize net revenues from the property.

 

Nacatimbay

 

We acquired a 100% working interest in the Nacatimbay block through two transactions. We purchased a 50% working interest in September 2005 and we purchased the remaining 50% working interest in November 2006. Production from the Nacatimbay oil, gas and condensate field began in 1996. Three wells were drilled and one was producing until February 28, 2006, when its production was suspended due to low flow conditions. In October 2006, the suspended well was reactivated after surface facilities were upgraded and it produced for two additional months in 2006 and three months of 2007 and is currently shut-in.   We continued to explore ways to optimize production in this field during 2007 and explored opportunities to re-enter the Nacatimbay 1001 well.

 

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The Nacatimbay block rights expire in 2022 with a provision for a ten year extension if a discovery is made. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government.

 

Ipaguazu

 

We acquired a 100% working interest in the Ipaguazu block through two transactions. We purchased a 50% working interest in September 2005 and we purchased the remaining 50% working interest in November 2006. The oil and gas field was discovered in 1981 and produced approximately 100 thousand barrels of oil and 400 million cubic feet of natural gas until 2003. No producing activities are carried out in the field at this time. The Ipaguazu block covers 43,243 acres and has not been fully appraised, leaving scope for both reactivation and exploration in the future.    The Ipaguazu block rights expire in 2016 with a ten year extension if a discovery is made. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government. In 2008, we plan to assess the possibility of a workover on the Ipaguazu X-1 well.

 

El Vinalar

 

We acquired a 50% working interest in the El Vinalar Block in June 2006. This acquisition added a significant new land position and a small amount of production. El Vinalar covers 248,341 acres and contains a portfolio of exploration leads and oil field enhancement opportunities. The Puesto Climaco-2 sidetrack well was successfully completed in December 2006, and began producing in January 2007.

 

Plans for 2008 include workovers of three wells - Puesto Climaco 3, Puesto Climaco 1 and El Vinalar 2.

 

The El Vinalar rights expire in 2016 with a ten year extension if a discovery is made. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government.

 

El Chivil, Surubi, Valle Morado, Santa Victoria

 

We purchased working interests in four additional properties at Chivil, Surubi, Valle Morado and Santa Victoria, in November and December 2006. These properties added to our existing portfolio of exploration and development opportunities and expanded our production base in Argentina. Farm-in partners are being sought to participate in drilling one exploration well on the Surubi block in 2008.

 

·

The Chivil field was discovered in 1987. Three wells were drilled; two remain in production. The field has produced 1.5 million barrels of oil to date. The contract for this field expires in 2015 with the option for a ten year extension.

 

·

Valle Morado was first drilled in 1989. Rights to the area were purchased by Shell in 1998, which subsequently completed a 3-D seismic program over the field and constructed a gas plant and pipeline infrastructure. Production began in 1999 from a single well, and was shut-in in 2001 due to water incursion. We are evaluating opportunities to re-establish production from the field.

 

·

Surubi and Santa Victoria are exploration fields and have no production history.

 

Oil and Gas Properties — Peru

We entered the Peruvian oil and gas industry in 2006 through the award of two frontier exploration blocks.

 

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Blocks 122 and 128

We were awarded two exploration blocks in Peru in the last quarter of 2006 under a license contract for the exploration and exploitation of hydrocarbons. Block 122 covers 1,217,651 acres and block 128 covers 2,218,389 acres. The blocks are located in the eastern flank of the Maranon Basin in northern Peru, on the crest of the Iquitos Arch. There is a 5-20%, sliding scale, royalty rate on the lands, dependent on production levels. Production less than 5,000 barrels of oil per day attracts a royalty of 5%, for production between 5,000 and 100,000 barrels of oil per day there is a linear sliding scale between 5% and 20%. Production over 100,000 barrels per day has a royalty of 20%.The exploration contracts expire in 2014 and work commitments are defined in four exploration periods spread over seven years. There is a financial commitment of $5 million over the seven years for each block which includes technical studies, seismic acquisition and the drilling of exploration wells. Acquisition of technical data through aero magnetic-gravity studies began in 2007, and is continuing through the first half of 2008. This will be followed by seismic planning work in 2008 and seismic acquisition 2009. The production contract expires in 2037.

Proved Reserves

 

No estimates of proved reserves comparable to those included herein have been included in a report to any federal agency other than the SEC.

The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A. “Risk Factors”. As a result we have developed internal policies for estimating and evaluating reserves, and 100% of our reserves are audited by an independent reservoir engineering firm at least annually.

 

The SEC definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:

·

Proved oil and natural gas reserves.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made as defined in Rule 4-10(a)(2). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

a)

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

b)

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

 

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c)

Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

 

·

Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as defined in Rule 4-10(a)(3).

·

Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required as defined in Rule 4-10(a)(4).

 

The following table sets forth our proved reserves net of all royalties and third party interests as of December 31, 2007. (all quantities in thousands of barrels of oil)

 

		Proved			Proved			Total			Proved
		Developed			Undeveloped			Proved			Reserves
		Reserves			Reserves			Reserves			%
Colombia
Santana			661			-			661			10.3	%
Guayuyaco			212			-			212			3.3	%
Juanambu			206			-			206			3.2	%
Costayaco			2,365			905			3,270			51.0	%
Mecaya			-			34			34			0.5	%
Total Colombia			3,444			939			4,383			68.3	%
Argentina
Palmar Largo			381			35			416			6.5	%
El Chivil			622			181			803			12.5	%
Ipaguazu			296			-			296			4.6	%
El Vinalar			520						520			8.1	%
Nacatimbay			-			-			-			0.0	%
Valle Morado			-			-			-			0.0	%
Total Argentina			1.819			216			2,035			31.7	%
Peru			-			-			-			-
Total			5,263			1,155			6,418			100.0	%

 

Our proved developed reserves set forth in the previous table, totaling 5.3 million barrels of oil as at December 31, 2007 consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2007. (all quantities in thousands of barrels of oil)

 

		Proved			Proved			Total Proved
		Developed			Developed			Developed
		Producing			Non-Producing			Reserves
Colombia
Santana			609			52			661
Guayuyaco			158			54			212
Juanambu			186			20			206
Costayaco			1,192			1,173			2,365
Mecaya			-			-			-
Total Colombia			2,145			1,299			3,444
Argentina
Palmar Largo			381			-			381
El Chivil			261			361			622
Ipaguazu			-			296			296
El Vinalar			334			186			520
Nacatimbay			-			-			-
Valle Morado			-			-			-
Total Argentina			976			843			1,819
Total Peru			-			-			-
Total			3,121			2,142			5,263

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Production Revenue and Price History

 

Certain information concerning oil and natural gas production, prices, revenues (net of all royalties) and operating expenses for the three years ended December 31, 2007 is set forth in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

 

Drilling Activities

 

The following table summarizes the results of our development and exploration drilling activity for the past three years. Wells labeled as “In Progress”, were in progress as of December 31, 2007.

 

		2007						2006						2005
		Gross			Net			Gross			Net			Gross			Net
Colombia
Exploration
Productive			2.00			0.85			-			-			1.00			0.35
Dry			4.00			1.50			1.00			1.00
In Progress			-			-			-			-			-			-
Development
Productive			-			-			-			-			1.00			0.35
Dry			-			-			-			-			-			-
In Progress			1.00			0.50			-			-			-			-
Total Colombia			7.00			2.85			1.00			1.00			2.00			0.70
Argentina
Exploration
Productive			-			-			-			-			-			-
Dry			-			-			-			-			-			-
In Progress			-			-			-			-			-			-
Development
Productive			1.00			0.50			1.00			0.14			1.00			0.14
Dry			-			-
In Progress			-			-			-			-			-			-
Total Argentina			1.00			0.50			1.00			0.14			1.00			0.14
Peru
Exploration
Productive			-			-			-			-			-			-
Dry			-			-			-			-			-			-
In Progress			-			-			-			-			-			-
Development
Productive			-			-			-			-			-			-
Dry			-			-			-			-			-			-
In Progress			-			-			-			-			-			-
Total Peru			-			-			-			-			-			-
Total			8.00			3.35			2.00			1.14			3.00			0.84

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Following are the results as of February 15, 2008 of wells in progress at December 31, 2007:

 

		Productive						Dry						Still in Progress
		Gross			Net			Gross			Net			Gross			Net
Colombia			1.00			0.50			-			-			-			-
Argentina			-			-			-			-			-			-
Peru			-			-			-			-			-			-
Total			1.00			0.50

 

Well Statistics

 

The following table sets forth our producing wells as of December 31, 2007.

 

		Oil Wells						Gas Wells						Total Wells
		Gross			Net			Gross			Net			Gross			Net
Colombia			19.00			6.71			-			-			19.00			6.71
Argentina			18.00			4.96			1.00			1.00			19.00			5.96
Peru			-			-			-			-			-			-
Total			37.00			11.67			1.00			1.00			38.00			12.67

 

Developed and Undeveloped Acreage

 

The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2007.

 

		Developed						Undeveloped						Total
		Gross			Net			Gross			Net			Gross			Net
Colombia			53,485			18,720			1,138,013			917,233			1,191,498			935,953
Argentina1			782,089			364,228			1,124,330			1,124,330			1,906,418			1,488,558
Peru			-			-			3,436,040			3,436,040			3,436,040			3,436,040
Total			835,574			382,948			5,698,383			5,477,603			6,533,956			5,860,551

 

¹ Effective January 1, 2008 we relinquished a total of 271,721 acres in Argentina within existing blocks. No blocks were relinquished in their entirety.

 

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At the Annual Meeting of Stockholders of Gran Tierra Energy Inc. held on October 10, 2007, the following proposals were adopted.

Proposal I - To elect the following directors to serve for the ensuing year and until their successors are elected:

		Voted For			Withheld			Broker Non-Votes
Dana Coffield			48,066,859			332,436			¾
Jeffrey Scott			48,065,959			333,336			¾
Walter Dawson			48,046,959			352,336			¾
Verne Johnson			48,045,959			353,336			¾
Nadine C. Smith			48,050,659			348,336			¾

 

Proposal II - To approve our 2007 Equity Incentive Plan, as an amendment and restatement of our 2005 Equity Incentive Plan, including an increase in the aggregate number of shares of common stock authorized for issuance under the plan from 2,000,000 to 9,000,000 shares:

 

Voted For		Voted Against			Abstain			Broker Non-Votes
35,614,922			2,282,260			339,050			10,163,063

 

Proposal III - To ratify the selection by the Audit Committee of Deloitte & Touche LLP as the independent registered public accounting firm of Gran Tierra Energy Inc. for the fiscal year ending December 31, 2007:

 

Voted For		Voted Against			Abstain			Broker Non-Votes
48,112,897			41,106			245,292			¾

 

 

     Set forth below is information regarding our executive officers as of February 28, 2008.

Name		Age		Position
Dana Coffield		49		President and Chief Executive Officer; Director
Martin H. Eden		60		Chief Financial Officer
Max Wei		58		Vice President, Operations
Rafael Orunesu		52		President, Gran Tierra Energy Argentina
Edgar Dyes		62		President, Argosy Energy/Gran Tierra Energy Colombia

     

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Dana Coffield, President, Chief Executive Officer and Director. Before joining Gran Tierra as President, Chief Executive Officer and a Director in May, 2005, Mr. Coffield led the Middle East Business Unit for EnCana Corporation, North America’s largest independent oil and gas company, from 2003 through 2005. His responsibilities included business development, exploration operations, commercial evaluations, government and partner relations, planning and budgeting, environment/health/safety, security and management of several overseas operating offices. From 1998 through 2003, he was New Ventures Manager for EnCana’s predecessor — AEC International — where he expanded activities into five new countries on three continents. Mr. Coffield was previously with ARCO International for ten years, where he participated in exploration and production operations in North Africa, SE Asia and Alaska. He began his career as a mud-logger in the Texas Gulf Coast and later as a Research Assistant with the Earth Sciences and Resources Institute where he conducted geoscience research in North Africa, the Middle East and Latin America. Mr. Coffield has participated in the discovery of over 130,000,000 barrels of oil equivalent reserves.      

 Mr. Coffield graduated from the University of South Carolina with a Masters of Science degree and a doctorate (PhD) in Geology, based on research conducted in the Oman Mountains in Arabia and Gulf of Suez in Egypt, respectively. He has a Bachelor of Science degree in Geological Engineering from the Colorado School of Mines. Mr. Coffield is a member of the AAPG and the CSPG, and is a Fellow of the Explorers Club.      

 Martin H. Eden, Chief Financial Officer. Mr. Eden joined our company as Chief Financial Officer on January 2, 2007. He has over 26 years experience in accounting and finance in the energy industry in Canada and overseas. He was Chief Financial Officer of Artumas Group Inc., a publicly listed Canadian oil and gas company from April 2005 to December 2006 and was a director from June to October, 2006. He has been president of Eden and Associates Ltd., a financial consulting firm, from January 1999 to present. From October 2004 to March 2005 he was CFO of Chariot Energy Inc., a Canadian private oil and gas company. From January 2004 to September 2004, he was CFO of Assure Energy Inc., a publicly traded oil and gas company listed in the United States. From January 2001 to December 2002, he was CFO of Geodyne Energy Inc., a publicly listed Canadian oil and gas company. From 1997 to 2000, he was Controller and subsequently CFO of Kyrgoil Corporation, a publicly listed Canadian oil and gas company with operations in Central Asia. He spent nine years with Nexen Inc. (1986-1996), including three years as Finance Manager for Nexen’s Yemen operations and six years in Nexen’s financial reporting and special projects areas in its Canadian head office. Mr. Eden has worked in public practice, including two years as an audit manager for Coopers & Lybrand in East Africa. Mr. Eden holds a Bachelor of Science degree in Economics from Birmingham University, England, a Masters of Business Administration from Henley Management College/Brunel University, England, and is a member of the Institute of Chartered Accountants of Alberta and the Institute of Chartered Accountants in England and Wales.

Max Wei, Vice President, Operations. Mr. Wei is a Petroleum Engineering graduate from University of Alberta and has twenty-five years of experience as a reservoir engineer and project manager for oil and gas exploration and production in Canada, the US, Qatar, Bahrain, Oman, Kuwait, Egypt, Yemen, Pakistan, Bangladesh, Russia, Netherlands, Philippines, Malaysia, Venezuela and Ecuador, among other countries. Mr. Wei began his career with Shell Canada and later with Imperial Oil, in Heavy Oil Operations. He moved to the US in 1986 to work with Bechtel Petroleum Operations at Naval Petroleum Reserves in Elk Hills, California and eventually joined Occidental Petroleum in Bakersfield. Mr. Wei returned to Canada in 2000 as Team Leader for Qatar and Bahrain operations with AEC International and its successor, EnCana Corporation, where he worked until 2004. He completed a project management position with Petronas in Malaysia in April, 2005, before joining Gran Tierra in May, 2005.

Mr. Wei is specialized in reservoir engineering, project management, production operations, field acquisition and development, and mentoring. He is a registered Professional Engineer in the State of California and a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta. Mr. Wei has a BSc in Petroleum Engineering from the University of Alberta and Certification in Petroleum Engineering from Southern Alberta Institute of Technology.

Rafael Orunesu, Vice President, Latin America. Mr. Orunesu joined Gran Tierra in March 2005 and brings a mix of operations management, project evaluation, production geology, reservoir and production engineering as well as leadership skills to Gran Tierra, with a South American focus. He was most recently Engineering Manager for Pluspetrol Peru, from 1997 through 2004, responsible for planning and development operations in the Peruvian North jungle. He participated in numerous evaluation and asset purchase and sale transactions covering Latin America and North Africa, incorporating 200,000,000 barrels of oil over a five-year period. Mr. Orunesu was previously with Pluspetrol Argentina from 1990 to 1996 where he managed the technical/economic evaluation of several oil fields. He began his career with YPF, initially as a geologist in the Austral Basin of Argentina and eventually as Chief of Exploitation Geology and Engineering for the Catriel Field in the Nuequén Basin, where he was responsible for drilling programs, workovers and secondary recovery projects.   

 

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Mr. Orunesu has a postgraduate degree in Reservoir Engineering and Exploitation Geology from Universidad Nacional de Buenos Aires and a degree in Geology from Universidad Nacional de la Plata, Argentina.

 Edgar Dyes, President Argosy Energy / Gran Tierra Energy Colombia. Mr. Dyes joined our company through the acquisition of Argosy Energy International L.P., where he was Executive Vice-President and Chief Operating Officer. His experience in the Colombian oil industry spans twenty-one years, with the last six years in charge of Argosy Energy’s planning, management, finance and administration activities. Mr. Dyes began his career with Union Texas Petroleum as a petroleum accountant, where he eventually advanced into supervision and management positions in international operations for the company. He subsequently worked for Quintana Energy Corporation; Jackson Exploration, Inc.; CSX Oil and Gas; and Garnet Resources Corporation, where he held the position of Chief Financial Officer. Mr. Dyes has worked in various financial and management roles on projects located in the United Kingdom, Germany, Indonesia, Oman, Brunei, Egypt, Somalia, Ecuador and Colombia. Mr. Dyes holds a Bachelor’s degree in Business Management from Stephen F. Austin State University, with postgraduate studies in accounting.

 

Our above-listed officers and directors have neither been convicted in any criminal proceeding during the past five years nor been parties to any judicial or administrative proceeding during the past five years that resulted in a judgment, decree or final order enjoining them from future violations of, or prohibiting activities subject to, federal or state securities laws or a finding of any violation of federal or state securities law or commodities law. Similarly, no bankruptcy petitions have been filed by or against any business or property of any of our directors or officers, nor has any bankruptcy petition been filed against a partnership or business association in which these persons were general partners or executive officers.

 

Our board of directors consists of six directors and includes two committees: an audit committee and a compensation committee. We adhere to the Nasdaq Marketplace Rules in determining whether a director is independent and our board of directors has determined that four of our six directors, Messrs. Scott, Johnson and Dawson and Ms. Smith, are “independent” within the meaning of Rule 4200(a)(15) of the NASD’s published listing standards.

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock was first cleared for quotation on the OTC bulletin board on November 11, 2005 and has been trading since that time under the symbol “GTRE.OB.” On February 19, 2008, our common stock was listed on the Toronto Stock Exchange (“TSX”) and is trading under the symbol “GTE”.

As of March 6, 2008 there were approximately 410 holders of record of shares of our common stock (including holders of exchangeable shares).

On March 6, 2008, the last reported sales price of our shares on the OTC bulletin board was $3.49. For the periods indicated, the following table sets forth the high and low bid prices per share of common stock. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions.

 

		High			Low
Fourth Quarter 2007		$	2.69		$	1.39
Third Quarter 2007		$	2.16		$	1.31
Second Quarter 2007		$	1.49		$	0.90
First Quarter 2007		$	1.64		$	0.88
Fourth Quarter 2006		$	1.75		$	1.10
Third Quarter 2006		$	3.67		$	1.47
Second Quarter 2006		$	5.01		$	2.96
First Quarter 2006		$	5.95		$	3.02

 

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As of March 6, 2008, there are 97,574,024 shares of common stock issued and outstanding, which number includes shares of common stock issuable upon exchange of the exchangeable shares of Goldstrike Exchange Co. issued to former holders of common stock of Gran Tierra Energy Inc, a privately held corporation in Alberta (“Gran Tierra Canada”).

Dividend Policy

 

Unregistered Sales of Equity Securities

 

None.

Performance Graph

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Item 6. Selected Financial Data

The following selected financial data should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in Item 8. “Financial Statements and Supplementary Data.” 

 

		Period Ended December 31,
		2007			2006			2005
Statement of Operations Data
Revenues and other income
Oil sales		$	31,807,641		$	11,645,553		$	946,098
Natural gas sales			44,971			75,488			113,199
Interest			425,542			351,872			—
Total revenues			32,278,154			12,072,913			1,059,297
Expenses
Operating			10,474,368			4,233,470			395,287
Depletion, depreciation and accretion			9,414,907			4,088,437			462,119
General and administrative			10,231,952			6,998,804			2,482,070
Liquidated damages			7,366,949			1,527,988			—
Derivative financial instruments			3,039,690			—			—
Foreign exchange (gain) loss			(77,275	)		370,538			(31,271	)
Total expenses			40,450,591			17,219,237			3,308,205
Loss before income tax			(8,172,437	)		(5,146,324	)		(2,248,908	)
Income tax			(294,767	)		(677,380	)		29,228
Net loss		$	(8,467,204	)	$	(5,823,704	)	$	(2,219,680	)
Net loss per common share — basic and diluted		$	(0.09	)	$	(0.08	)	$	(0.16	)
Statement of Cash Flows Data			(As Restated)(1)			(As Restated)(1)
Operating activities		$	8,761,439		$	2,010,056		$	(1,876,638	)
Investing activities			(15,392,705	)		(48,206,588	)		(9,108,022	)
Financing activities			719,303			68,075,856			13,206,116
(Decrease) Increase in cash		$	(5,911,963	)	$	21,879,324		$	2,221,456
Balance Sheet Data
Cash and cash equivalents		$	18,188,817		$	24,100,780		$	2,221,456
Working capital (including cash)			8,058,049			14,541,498			2,764,643
Oil and gas properties			63,202,432			56,093,284			7,886,914
Deferred tax asset			2,058,436			444,324			—
Total assets			112,796,561			105,536,957			12,371,131
Deferred tax liability			(11,674,744	)		(9,875,657	)		—
Other long-term liabilities			(1,986,023	)		(633,683	)		(67,732	)
Shareholders’ equity		$	(76,791,855	)	$	(76,194,779	)	$	(11,039,347	)

 

⁽¹⁾ As discussed in Note 13 to our consolidated financial statements, cash flows from operating activities and cash flows from investing activities has been restated as a result of a misclassification of accounts payable and accrued liabilities between the two categories.

 

We made our initial acquisition of oil and gas producing and non-producing properties in Argentina in September 2005 for a total purchase price of approximately $7 million. Prior to that time we had no revenues. In June 2006, we acquired our Argosy assets for consideration of $37.5 million cash, 870,647 shares of our common stock and overriding and net profit interests in certain assets valued at $1 million.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto. Except for the historical information contained herein, the matters discussed below are forward-looking statements that involve risks and uncertainties, including, among others, the risks and uncertainties discussed below.

Overview

 

We are an independent international energy company involved in oil and natural gas exploration, development and production. We plan to continually increase our oil and natural gas reserves through a balanced strategy of exploration drilling, development and acquisitions in South America. Initial countries of interest are Argentina, Colombia and Peru.

We took our current form on November 10, 2005 when the former Gran Tierra Energy Inc., a privately-held Alberta corporation, which we refer to as Gran Tierra Canada, was acquired by an indirect subsidiary of Goldstrike Inc, a Nevada corporation. Goldstrike adopted the assets, management, business operations, business plan and name of Gran Tierra Canada. For accounting purposes, the predecessor company in the transaction was the former Gran Tierra Canada, and the financial information of the former Goldstrike was eliminated at consolidation. This transaction is accounted for as a reverse takeover of Goldstrike Inc. by Gran Tierra Canada.

Prior to September 1, 2005, we had no oil and gas interests or properties. In September 2005 and during 2006 we acquired oil and gas interests and properties in Argentina, Colombia and Peru.

We funded acquisitions of our properties in Colombia and Argentina through a series of private placements of our securities that occurred between September 2005 and February 2006 and an additional private placement that occurred in June 2006, described below.

Our operating results for the year ended December 31, 2007 as compared to 2006 are principally impacted by the inclusion in 2007 of a full year’s activities from the oil and gas interests in Argentina and Colombia we acquired in the second and fourth quarters of 2006. The 2007 results are also impacted by the 2007 discoveries in the Costayaco area of the Chaza block and the Juanambu area of the Guayuyaco block and the subsequent commencement of production of the first wells in each of these areas in the second half of 2007 and a higher average WTI for 2007. Our production volumes and revenues in Colombia have significantly increased over the prior year.

The operating results for 2006 include a full year of activities at Palmar Largo, two months at Nacatimbay before production was suspended on March 1, 2006 and two months after production was reinstated on November 1, 2006, six months of activities at El Vinalar beginning July 1, 2006 and one month of activities at Chivil, commencing December 1, 2006. We initially held a 14% working interest (WI) in Palmar Largo (oil production), a 50% WI in Nacatimbay (production of natural gas and condensate) and a 50% WI in Ipaguazu (exploration land). During November and December of 2006 we acquired the following additional working interests in Argentina, which further impacted the financial and operational results for the year ended December 31, 2007:

· an additional 50% WI in Nacatimbay;

· an additional 50% WI in Ipaguazu;

· 50% WI in El Vinalar (oil production);

· 100% WI in Chivil (oil production);

· 100% WI in Surubi (exploration land);

· 100% WI in Santa Victoria (exploration land); and,

· 93.2% WI in Valle Morado (exploration land).

The operating results for 2006 were also impacted by our acquisition of Argosy Energy International L.P. (“Argosy”). Prior to June 20, 2006 we did not own any oil or gas properties in Colombia. On June 20, 2006 we acquired Argosy and became the operator of nine blocks in Colombia. The Santana, Guayuyaco and Chaza blocks are currently producing. The Rio Magdalena, Talora, Azar and Mecaya blocks are in their exploration phases. During 2007, we relinquished ownership of the Primavera block and acquired the Putumayo A and B technical evaluation areas.

The operating results and financial position for 2005 reflect our incorporation on January 26, 2005 and the commencement of oil and gas operations in Argentina on September 1, 2005.

 

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Due to a successful exploration program in Colombia, undertaken in the first half of 2007, we made two field discoveries, Costayaco in the Chaza block and Juanambu in the Guayuyaco block. These exploration wells were brought into production in the third quarter of 2007 and have significantly increased our daily production. Average daily production in Colombia in 2007, including our new discovery wells Costayaco-1 and Juanambu-1, increased by 559 barrels per day to 913 barrels per day from 354 barrels per day in 2006.

Our estimate of proved reserves, net of royalties, as of December 31, 2007, stands at 6.4 million barrels of oil primarily due to the new discoveries at Costayaco and Juanambu.  This compares to our December 31, 2006 proved reserves of 3.0 million barrels of oil. 

Effective February 28, 2007, we entered into a credit facility with Standard Bank Plc. The facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of our petroleum reserves up to maximum of $50 million, with an initial borrowing base of $7 million based on mid-2006 reserves. We have not drawn down any amounts under this facility.

In June, 2006, we sold an aggregate of 50 million units of our securities at a price of $1.50 per unit in a private offering for gross proceeds of $75 million, pursuant to four separate Securities Purchase Agreements, which we refer to collectively as the “2006 Offering”. Each unit comprised one share of Gran Tierra Energy’s common stock and one warrant to purchase one-half of a share of Gran Tierra Energy’s common stock at an exercise price of $1.75 for a period of five years. In connection with the issuance of these securities, Gran Tierra Energy entered into four separate Registration Rights Agreements with the investors pursuant to which Gran Tierra Energy agreed to register for resale the shares and warrants (and shares issuable pursuant to the warrants) issued to the investors in the offering by November 17, 2006, and if we failed to do so we would be obligated to pay liquidated damages. The second registration statement was declared effective by the Securities Exchange Commission (“SEC”) on May 14, 2007. Gran Tierra Energy had accrued $8.6 million in liquidated damages as of that date.

On June 27, 2007, under the terms of the Registration Rights Agreements, we obtained a sufficient number of consents from the signatories to the agreements waiving Gran Tierra Energy’s obligation to pay in cash the accrued liquidated damages. We agreed to amend the terms of the warrants issued in the 2006 Offering by reducing the exercise price of the warrants to $1.05 and extending the life of the warrants by one year, in lieu of a cash payment for liquidated damages. $7.4 million of the liquidated damages has been recorded in 2007 and the remainder had been recorded in 2006.

Gran Tierra Energy has an active development drilling and exploration drilling program budgeted for 2008. This includes seven development wells in oil discoveries made in Colombia in 2007 including Costayaco-2 which commenced drilling in December 2007, and completed testing in February 2008; Costayaco-3 which was drilled in January and February 2008 and is planned for testing in March, 2008; and three oil exploration wells, two in Colombia and one in Argentina. Our exploration success in 2007 is to be further developed in 2008 with the potential to significantly increase our production. Gran Tierra Energy plans to continue with development drilling through 2008 to increase our production capacity, in addition to undertaking additional oil exploration efforts to further define the potential of our acreage in Colombia, Argentina and Peru.

Currently all oil and gas producers in Argentina are operating without sales contracts.   A new withholding tax regime was introduced in Argentina without specific guidance as to its application. Producers and refiners of oil in Argentina have been unable to determine an agreed sales price for oil deliveries to refineries. We are receiving $33 per barrel, which is a price offered by Refiner S.A., the purchaser of our crude oil, based on their netback, for production since November 18, 2007, the effective date of the decree.  The price we received for November oil deliveries before November 18, 2007 was approximately $48 per barrel.  Along with most other oil producers in Argentina, we are continuing deliveries to the refinery and will continue to receive $33 per barrel until the situation around the decree is rectified by the government.  The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced by the lower sales price. We are working with other oil and gas producers in the area, as well as Refiner S.A. and provincial governments, to lobby the federal government for change. There has been a delay in rectifying the situation in Argentina because of a change in government in December 2007, and the months of January and February are generally slow working months due to summer vacations.

Operating in countries in South America exposes our business to risks due to political and economic forces in the countries in which we operate. For example, in March 2008, one of the Ecopetrol pipelines was blown up by guerillas, and we estimate at present that we will have to reduce our current production deliveries to Ecopetrol for approximately one week, perhaps longer, while Ecopetrol completes repairs to their pipeline, which will impact our revenues for the first quarter of 2008. See Item 1A. “Risk Factors” for the risks we face as a result of operating in South America.

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Results of Operations for the years ended December 31, 2007 as compared to year ended December 31, 2006

Revenue and Other Income

 

A summary of selected production, revenue and price information for the years ended December 31, 2007 and 2006 is presented in the following table: 

		Year Ended December 31,
		2007									2006									Change from Prior Year
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
Production, net of royalties (2)
Oil and NGLs (Bbls)			207,912			333,157			541,069			127,712			129,209			256,921			63	%		158	%		111	%
Gas (Mcf)			26,631			-			26,631			41,447			-			41,447			-36	%		-			-36	%
Oil, Gas and NGLs (Boe) (1)			209,244			333,157			542,401			129,784			129,209			258,993			61	%		158	%		109	%
Revenue and other income
Oil and NGLs (Bbls)		$	8,059,486		$	23,748,155		$	31,807,641		$	5,033,363		$	6,612,190		$	11,645,553			60	%		259	%		173	%
Gas			44,971			-			44,971			75,488			-			75,488			-40	%		-			-40	%
Interest (excluding Corporate)			15,225			222,785			238,010			-			-			-			100	%		100	%		100	%
		$	8,119,682		$	23,970,940		$	32,090,622		$	5,108,851		$	6,612,190		$	11,721,041			59	%		263	%		174	%
Other - Corporate									187,532									351,872									-47	%
								$	32,278,154								$	12,072,913									167	%
Average Prices
Oil and NGLs (Per Bbl)		$	38.76		$	71.28		$	58.79		$	39.41		$	51.17		$	45.33			-2	%		39	%		30	%
Gas (Per Mcf)		$	1.69			-		$	1.69		$	1.82			-		$	1.82			-7	%		-			-7	%

 

(1) Gas volumes are converted to barrels (“bbl’s”) of oil equivalent ("Boe") at the rate of 20 thousand cubic feet ("Mcf") of gas per barrel of oil based upon the approximate relative values of natural gas and oil. Natural Gas Liquids (NGLs") volumes are converted to Boe’s on a one-to-one basis with oil.   (2) Production represents production volumes adjusted for inventory changes.

 

Crude oil and NGL production for the year ended December 31, 2007 increased 111% to 541,069 barrels from 256,921 barrels for the year ended December 31, 2006. The average price received per barrel of oil increased 30% to $58.79 per barrel for 2007 from $45.33 per barrel in 2006. As a result, revenues and other income for the year ended December 31, 2007 increased 167% to $32,278,154 compared to $12,072,913 for the year ended December 31, 2006. The increase in production is due primarily to the inclusion of a full year of Colombian and Argentine production and the commencement of production at the beginning of the third quarter from the two new discovery wells. The 2006 production included Colombian production subsequent to its acquisition in June 2006. In Argentina, the 2006 results include a full year of activities at Palmar Largo, four months at Nacatimbay, six months of activities at El Vinalar beginning July 1, 2006, and one month of activities at Chivil, commencing December 1, 2006. Natural gas production in 2007 decreased 36% to 26,631 Mcf from 41,447 Mcf in 2006 with the average price also decreasing 7% to $1.69 per Mcf from $1.82 per Mcf. The volume decrease was a result of an operations decision to use the gas production for operating power generation and market only the unused excess.

In Argentina, crude oil and NGL production after 12% royalties for the year ended December 31, 2007 increased 63% to 207,912 barrels compared to 127,712 barrels for 2006. This increased production includes 89,361 barrels from Palmar Largo, 77,971 barrels from El Vinalar and 40,039 barrels from Chivil. Average daily production for the year was 245 barrels from Palmar Largo, 214 barrels from El Vinalar and 110 barrels from Chivil. Natural gas production, after royalties of 12%, at Nacatimbay in 2007 was 26,631 Mcf as compared to 41,447 Mcf in 2006. For 2006, Argentina’s crude oil production after 12% royalties was 127,712 barrels, including 118,121 barrels from Palmar Largo, 7,644 barrels from El Vinalar for the period July 1 to December 31, 2006, and 1,947 barrels from Chivil for December 1 to December 31, 2006. Average daily production for these periods in 2006 was 324 barrels from Palmar Largo, 42 barrels from El Vinalar (21 barrels per day for the year) and 63 barrels (5 barrels per day for the year) from Chivil.

In Argentina, net revenue for the year ended December 31, 2007, after deducting royalties at an average royalty rate of 12% of production revenue, and after deducting turnover taxes, increased 60% to $8,059,486 ($38.76 per barrel) for oil and NGLs and decreased 40% to $44,971 ($1.69 per Mcf) for natural gas as compared to $5,033,363 ($39.41 per barrel) and $75,488 ($1.82 per Mcf), respectively, for 2006. Oil and natural gas prices are effectively regulated in Argentina. Although production from most properties has increased due to a full year’s production in 2007 as compared to 2006, domestic prices received have decreased due to the impact of increased export taxes levied by the Federal Government.

In Colombia, crude oil and NGL production, after government royalties ranging from 8% to 20% and a third party two percent overriding royalty, for the year ended December 31, 2007 increased 158% to 333,157 barrels as compared to 129,209 barrels for 2006. This increased production includes 112,662 barrels from the Santana block, 60,533 barrels from the Guayuyaco block (excluding the Juanambu area), 38,119 barrels from the Juanambu area and 125,163 barrels from the Chaza block (Costayaco area). The average daily production for the year was 309 barrels per day from the Santana block, 166 barrels per day from the Guayuyaco block (excluding the Juanambu area), and 104 barrels per day from the Juanambu area and 343 per day from the Chaza block. For 2006, Colombia’s production and results of operations commenced June 21, 2006 in conjunction with our acquisition of Argosy. Production after royalties was 129,209 barrels for the period from June 21 to December 31, 2006, comprising 65,176 barrels from the Santana block and 64,033 barrels from the Guayuyaco block, representing a combined average production rate of 692 barrels per day for the period (354 barrels per day for the year). The significant increase is as result of a full year of production and two new discoveries, one in the Juanambu area of the Guayuyaco block and the other in the Costayaco area of the Chaza block which came on production in the third quarter of 2007.

 

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In Colombia, crude oil and NGL revenue, net of royalties, for the year ended December 31, 2007 increased 259% to $23,748,155 or $71.28 per barrel as compared to $6,612,190 and $51.17 per barrel for 2006. Besides the increase in production as a result of the new discovery wells and a full year of production from the other areas, revenue increased due to the increased price of oil received based on a higher WTI price in 2007.

Interest income earned on our cash deposits for the year ended December 31, 2007 increased 21% to $425,542 as compared to $351,872 for 2006. Although our cash balances held by corporate from funds raised mid-year 2006 through private placements have decreased, the increase in receipts from crude oil sales throughout 2007 has offset this decrease, resulting in an increase in interest revenue.

Operating Expenses

		Year Ended December 31,
		2007									2006									Change from Prior Year
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
Operating Expense
Operating Expense		$	6,327,276		$	4,097,336		$	10,424,612		$	2,846,705		$	1,386,765		$	4,233,470			122	%		195	%		146	%
Other - Corporate - Peru Operations									49,756									-									100	%
		$	6,327,276		$	4,097,336		$	10,474,368		$	2,846,705		$	1,386,765		$	4,233,470									147	%
Operating expense per Boe		$	30.24		$	12.30		$	19.31		$	21.93		$	10.73		$	16.35			38	%		15	%		18	%

For the year ended December 31, 2007, operating expenses increased 147% to $10,474,368 ($19.31 per Boe) compared to $4,233,470 ($16.35 per Boe) in 2006, reflecting the inclusion in 2007 of a full year of Colombian and Argentine operating activities for those properties. The operations for the new discovery wells at Juanambu and Costayaco commenced in the third quarter of 2007 contributing to the increase in operating costs. In 2006, Argentina’s operations included a full year operations at Palmar Largo, four months at Nacatimbay, six months of activities at El Vinalar and one month at Chivil. Colombia’s operations commenced June 21, 2006 as a result of the purchase of Argosy.

In Argentina, operating expenses for 2007 increased 122% to $6,327,276 ($30.24 per Boe) as compared to $2,846,705 for 2006 ($21.93 per Boe). The 2007 operating costs are higher than in 2006 due to workovers undertaken in 2007. Argentina’s 2007 operating costs include $9.71 per Boe ($2.27 per Boe in 2006) of costs associated with budgeted workover projects undertaken to sustain production.

In Colombia, operating expenses increased 195% to $4,097,336 in 2007 ($12.30 per Boe) as compared to $1,386,765 for the period June 21 to December 31, 2006 ($10.73 per Boe). The 2007 operating costs included $2.69 per Boe ($4.11 per Boe in 2006) of budgeted workover expense mainly carried out in the Guayuyaco block.

Depletion, Depreciation and Accretion (“DD&A”)

		Year Ended December 31,
		2007									2006									Change from Prior Year
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
DD&A
DD&A		$	2,476,834		$	6,850,086		$	9,326,920		$	1,550,544		$	2,494,317		$	4,044,861			60	%		175	%		131	%
Other - Corporate									87,987									43,576									102	%
								$	9,414,907								$	4,088,437									130	%
DD&A per Boe		$	11.84		$	20.56		$	17.36		$	11.95		$	19.30		$	15.79			-1	%		7	%		10	%

    

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Depreciation, depletion and accretion for the year ended December 31, 2007 increased 130% to $9,414,907 from $4,088,437 for 2006. For Argentina, DD&A increased 60% to $2,476,834 from $1,550,544 in 2006. The increase in Argentina is mainly due to decreased proved reserves offset by a decreasing proved depletable cost base resulting in an 1% decrease of the DD&A rate to $11.84 per Boe in 2007 from $11.95 per Boe in 2006. This decreasing proved depletable cost base is a result of the mature nature of the properties held and our 2007 focused capital spending on the Colombian exploration program.

For Colombia, DD&A increased 175% to $6,850,086 from $2,494,317 for 2006. The increase in Colombia is primarily due to the increase in production over the prior year. Though our Colombian proved reserves increased significantly in 2007, Gran Tierra Energy also invested much of its 2007 capital spending on the Colombia exploration program. As a result, our Colombian proved depletable cost base has significantly increased resulting in a 2007 depletion rate of $20.56 per Boe as compared to $19.30 per Boe for 2006.

The 2006 DD&A includes a full year of operations at Palmar Largo, additional Argentina acquisitions in 2006, and the inclusion of Colombia operations in June 2006.

General and Administrative (“G&A”)

		Year Ended December 31,
		2007									2006									Change from Prior Year
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
G&A
G&A		$	1,704,410		$	1,695,825		$	3,400,235		$	1,122,980		$	897,494		$	2,020,474			52	%		89	%		68	%
Other - Corporate								$	6,831,717								$	4,978,330									37	%
								$	10,231,952								$	6,998,804									46	%
G&A per Boe		$	8.15		$	5.09		$	18.86		$	8.65		$	6.95		$	27.02			-6	%		-27	%		-30	%

General and administrative costs for the year ended December 31, 2007 increased 46% to $10,231,952 from $6,998,804 for 2006. The increase in G&A was due to the inclusion of a full year of business activities related to the acquisition of the Argosy properties in Colombia and additional properties in Argentina, corporate stewardship costs including Sarbanes Oxley compliance, securities registration related costs and increased stock compensation due to increased option grants. Argentina’s G&A cost for the year ended December 31, 2007 increased 52% to $1,704,410 from $1,122,980 in 2006 as a result of the need for increased administration staff and professional costs associated with properties purchased late in 2006. Colombia’s G&A for the year ended December 31, 2007 increased 89% to $1,695,825 from $897,494 in 2006 mainly due to 2006 G&A costs include those costs during the period commencing on the date of acquisition of Argosy, to the year end.

Liquidated Damages

    

		Year Ended December 31,						Change from Prior
		2007			2006			Year
Liquidated Damages		$	7,366,949		$	1,527,988			382	%

Liquidated damages expensed in 2007 relates to liquidated damages payable to our stockholders as a result of the registration statement for 50 million units sold in the second quarter of 2006 not becoming effective within the period specified in the share registration rights agreements for those securities. This registration statement became effective on May 14, 2007.

On June 27, 2007, under the terms of the Registration Rights Agreements, we obtained a sufficient number of consents from the signatories to the agreements waiving our obligation to pay in cash the accrued liquidated damages. We agreed to amend the terms of the warrants issued in the 2006 offering by reducing the exercise price of the warrants from $1.75 to $1.05 and extending the life of the warrants by one year.

The amendment to the terms of the warrants has been reflected as an increase of $8.6 million in the value of warrants recorded on the consolidated balance sheet.

Financial Derivative Loss

Financial Derivative Loss		Year Ended December 31, 2007
Realized financial derivative loss		$	391,345
Current portion of unrealized financial derivative Loss		$	1,593,629
Long-term portion of unrealized financial derivative loss		$	1,054,716
Total unrealized financial derivative loss		$	2,648,345
Financial derivative loss		$	3,039,690

39

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As required under the terms of the Credit Facility with Standard Bank Plc, in February of 2007, we entered into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. In accordance with the terms of the Facility, Gran Tierra Energy is required to maintain compliance with specified financial and operating covenants.

Foreign Exchange Loss

		Year Ended December 31,						Change from Prior
		2007			2006			Year
Foreign Exchange (Gain) Loss		$	(77,275	)	$	370,538			121	%

The foreign exchange gain for the year ended December 31, 2007 increased to $77,275 from a loss of $370,538 for 2006. The foreign exchange gain resulted from the increase in 2007 of the value of the Colombian peso as compared to the US dollar.

Income Tax

		Year Ended December 31,						Change from Prior
		2007			2006			Year
Income Tax		$	294,767		$	677,380			-56	%

The income tax expense for the year ended December 31, 2007 decreased 56% to $294,767 from $677,380 for 2006. The Colombia operations generated a net income before tax of $11,484,448 in 2007, which resulted in a local income tax liability, offset by a 2007 income tax recovery arising from losses of $2,740,990 incurred in Argentina. In Colombia, we have used available prior period loss carryforwards and Colombian income tax investment incentives, which permit additional tax deductions associated with capital investment in producing oil and natural gas properties, to decrease our current income tax otherwise payable.

Net Income (Loss) Available to Common Shares

		Year Ended December 31,
		2007												2006												Change from Prior Year
		Argentina			Colombia			Corporate			Total			Argentina			Colombia			Corporate			Total			Argentina			Colombia			Corporate			Total
Net Loss
Net loss (income) before income tax		$	2,474,990		$	(11,484,448	)	$	17,181,895		$	8,172,437		$	411,028		$	(1,486,075	)	$	6,221,371		$	5,146,324			502	%		673	%		176	%		59	%
Income tax									-			294,767												677,380												-56	%
Net Loss											$	8,467,204											$	5,823,704												45	%
Loss per share - Basic and Diluted
Weighted Average Outstanding Common Shares - Basic and Diluted												95,096,311												72,443,501												31	%
Loss per share - Basic and Diluted											$	0.09											$	0.08												13	%

The net loss for the year ended December 31, 2007 increased 45% to $8,467,204 or $0.09 per share from a loss of $5,823,704, or $0.08 per share in 2006. This loss includes a full year of operating activities for Colombia versus just over six months in 2006. The primary reason for the increase is due to the liquidated damages, as explained above, corporate stewardship costs including Sarbanes Oxley compliance, securities registration related costs and increased stock compensation due to increased option grants. Argentina’s 2007 operating segment loss increased 502% to $2,474,990 from a loss of $411,028 in 2006 primarily due to the increase in budgeted workover costs required to maintain production levels. Colombia increased its 2007 operating segment income by 673% to $11,484,448 from $1,486,075 in 2006 is a result to the increased production realized from the new discovery wells and the increase in price received for all production in 2007 versus 2006.

 

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Results of Operations for the years ended December 31, 2006 as compared to period ended December 31, 2005

Revenue and Other Income

A summary of selected production, revenue and price information for the year ended December 31, 2006 and the period ended December 31, 2005 is presented in the following table: 

		Year Ended December 31, 2006									Periods Ended December 31, 2005									Change from Prior Period
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
Production, net of royalties (2)
Oil and NGLs (Bbls)			127,712			129,209			256,921			25,132			-			25,132			408	%		100	%		922	%
Gas (Mcf)			41,447			-			41,447			180,320			-			180,320			-77	%		-			-77	%
Oil, Gas and NGLs (Boe) (1)			129,784			129,209			258,993			34,148			-			34,148			280	%		100	%		658	%
Revenue and other income
Oil and NGLs (Bbls)		$	5,033,363		$	6,612,190		$	11,645,553		$	946,098			-		$	946,098			432	%		100	%		1,131	%
Gas			75,488			-			75,488			113,199			-		$	113,199			-33	%		-			-33	%
		$	5,108,851		$	6,612,190		$	11,721,041		$	1,059,297			-		$	1,059,297			382	%		100	%		1,006	%
Other - Corporate								$	351,872									-									100	%
								$	12,072,913								$	1,059,297									1,040	%
Average Prices
Oil and NGLs (Per Bbl)		$	39.41		$	51.17		$	45.33		$	37.65			-		$	37.65			5	%		100	%		20	%
Gas (Per Mcf)		$	1.82			-		$	1.82		$	0.63			-		$	0.63			189	%		-			189	%

 

(1) Gas volumes are converted to barrels (“bbl’s”) of oil equivalent ("Boe") at the rate of 20 thousand cubic feet ("Mcf") of gas per barrel of oil based upon the approximate relative values of natural gas and oil. Natural Gas Liquids (NGLs") volumes are converted to Boe’s on a one-to-one basis with oil.

 

(2) Production represents production volumes adjusted for inventory changes.

Crude oil and NGL production for the year ended December 31, 2006 increased 922 % to 256,921 barrels from 25,132 barrels for the year ended December 31, 2005. The average price received per barrel of oil increased 20% to $45.33 per barrel for 2006 from $37.65 per barrel in 2005. As a result, revenue and other income for the year ended December 31, 2006 increased 1,040% to $12,072,913 compared to $1,059,297 for the year ended December 31, 2005. The 2006 production included Colombian production subsequent to the acquisition of Argosy in June 20, 2006. Also, in Argentina, the 2006 results include a full year of activities at Palmar Largo, four months at Nacatimbay, six months of activities at El Vinalar beginning July 1, 2006, and one month of activities at Chivil, commencing December 1, 2006. Revenues in 2005 reflect only the Argentina operations for a four month period from September 1, 2005, the date of acquisition of the Palmar Largo and Nacatimbay properties. Natural gas production in 2006 decreased 77% to 41,447 Mcf from 180,320 Mcf in 2006 with the average price increasing 189% to $1.82 per Mcf from $0.63 per Mcf. The volume decrease was a result of an operations decision to use the gas production for operating power generation and market only the unused excess.

 

In Argentina, crude oil and NGL production after 12% royalties for the year ended December 31, 2006 increased 408% to 127,712 barrels compared to 25,132 barrels for 2005. This increased production includes 118,121 barrels from Palmar Largo, 7,644 barrels from El Vinalar for the period July 1 to December 31, 2006, and 1,947 barrels from Chivil for December 1 to December 31, 2006. Average daily production for these periods in 2006 was 324 barrels from Palmar Largo, 42 barrels from El Vinalar (21 barrels per day for the year) and 63 barrels (5 barrels per day for the year) from Chivil. Oil sales at Palmar Largo during 2005 were 25,132 barrels, or an average of 206 barrels per day for the period (69 barrels per day for the year), due to severe weather conditions in Northern Argentina, as extreme rainfall and poor road conditions curtailed tanker truck traffic through November and December 2005. Natural gas sales, after royalties of 12%, at Nacatimbay in 2006 were 41,447 Mcf as compared to 180,320 Mcf in 2005.

In Argentina, net revenue for the year ended December 31, 2006, after deducting royalties at an average royalty rate of 12% of production revenue, and after deducting turnover taxes, increased 432% to $5,033,363 ($39.41 per barrel) for oil and NGLs and decreased 33% to $75,488 ($1.82 per Mcf) for natural gas as compared to $946,098 ($37.65 per barrel) and $113,199 ($0.63 per Mcf), respectively, for 2005. Increased production from most properties due to a full year’s production in 2006 as compared to a partial year’s production in 2005 and increased prices received due to increased world oil prices in 2006 as compared to 2005 have resulted in the increase in net revenue. Oil and natural gas prices are effectively regulated in Argentina.

 

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In Colombia, crude oil and NGL production, after royalties ranging from 10% to 22% (including a 2 percent overriding royalty), for the year ended December 31, 2006 increased 100% to 129,209 barrels as compared to nil production for 2005. Colombia’s production and results of operations began June 21, 2006 in conjunction with our acquisition of Argosy. Production after royalties was comprised of 65,176 barrels from the Santana block and 64,033 barrels from the Guayuyaco block, representing a combined average production rate of 692 barrels per day for the period (354 barrels per day for the year).

In Colombia, crude oil and NGL revenue, net of royalties, for the year ended December 31, 2006 increased 100% to $6,612,190 and $51.17 per barrel as compared to no revenue for 2006.

Interest income earned on our cash deposits was $351,872 for the year ended December 31, 2006 and none in 2005.

Operating Expenses

    

		Year Ended December 31,									Period Ended December 31,
		2006									2005									Change from Prior Year
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
Operating Expense
Operating Expense		$	2,846,705		$	1,386,765		$	4,233,470		$	395,287		$	-		$	395,287			620	%		100	%		971	%
Operating Expense per Boe		$	21.93		$	10.73		$	16.35		$	11.58					$	11.58			89	%		100	%		41	%

For the year ended December 31, 2006, operating expenses increased 971% to $4,233,470 ($16.35 per Boe) compared to $395,287 ($11.58 per Boe) in 2005, reflecting the inclusion in Argentina of operations for a full year at Palmar Largo, four months at Nacatimbay, six months of activities at El Vinalar and one month at Chivil. Colombia’s operations commenced June 21, 2006 as a result of the purchase of Argosy. Operating expenses totaled $395,287 for the period from incorporation on January 26, 2005 to December 31, 2005, representing four months of operations in Argentina.

In Argentina, operating expenses for 2006 increased 620% to $2,846,705 ($21.93 per Boe) as compared to $395,287 for 2005 ($11.58 per Boe). The current year operating costs are higher than in the same periods of 2006 due to workovers undertaken in the current year, and 2005 contains only four months of operations commencing from the initial purchase of Argentine assets.

In Colombia, operating expenses were $1,386,765 ($10.73 per Boe) for the period June 21 to December 31, 2006. Colombia’s 2006 operating costs included $4.11 per Boe of budgeted workover expense carried out in the Guayuyaco and Santana blocks.

Depletion, Depreciation and Accretion 

		Year Ended December 31,									Period Ended December 31,
		2006									2005									Change from Prior Period
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
DD&A
DD&A		$	1,550,544		$	2,494,317		$	4,044,861		$	453,022		$	-		$	453,022			242	%		100	%		793	%
Other - Corporate								$	43,576								$	9,097									379	%
								$	4,088,437								$	462,119									785	%
DD&A per Boe		$	11.95		$	19.30		$	15.79		$	13.27			-		$	13.53			-10	%		100	%		17	%

Depreciation, depletion and accretion for the year ended December 31, 2006 increased 785% to $4,088,437 from $462,119 for 2005. The 2006 DD&A includes a full year of operations at Palmar Largo, additional Argentina acquisitions in 2006, and the inclusion of Colombia operations in June 2006. Depreciation, depletion and accretion recorded in 2005 primarily relates to the depletion of the acquisition cost for the Argentina properties.

 

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General and Administrative

		Year Ended December 31,									Period Ended December 31,
		2006									2005									Change from Prior Period
		Argentina			Colombia			Total			Argentina			Colombia			Total			Argentina			Colombia			Total
G&A
G&A		$	1,122,980		$	897,494		$	2,020,474		$	331,033		$	-		$	331,033			239	%		100	%		510	%
Other - Corporate								$	4,978,330								$	2,151,037									131	%
								$	6,998,804								$	2,482,070									182	%
G&A per Boe		$	8.65		$	6.95		$	27.02		$	9.69					$	72.69			-11	%		100	%		-63	%

General and administrative costs for the year ended December 31, 2006 increased 182% to $6,998,804 from $2,482,070 for 2006. The incremental increase in general and administrative costs in 2006 was primarily due to operating fully-staffed branch offices in Colombia and Argentina, the increased level of activity related to our expansion of operations, which resulted from acquisition of the Argosy assets in Colombia and properties in Argentina, and costs related to the registration of our securities.

Liquidated Damages

		Year Ended December 31,			Period Ended December 31,			Change from Prior
		2006			2005			Period
Liquidated Damages		$	1,527,988		$	-			100	%

Liquidated damages of $1,527,988 recorded in 2006 relate to liquidated damages payable to our stockholders as a result of the registration statements for our securities issued in 2005 and 2006 not becoming effective within the periods specified in the share registration rights agreements for those securities. The amount expensed includes $269,923 related to 15,047,606 units issued in the fourth quarter of 2005 and first quarter of 2006 and $1,258,065 related to 50 million units sold in the second quarter of 2006. We did not have any liquidated damages in 2005.

Foreign Exchange Loss

		Year Ended December 31,			Period Ended December 31,			Change from Prior
		2006			2005			Period
Foreign Exchange (Gain) Loss		$	370,538		$	(31,271	)		1,285	%

The foreign exchange loss for the year ended December 31, 2006 increased to $370,538 from a gain of $31,271 for 2005. The loss arose primarily from translation of local currency denominated transactions in our South American operations into US dollars.

Income Tax

   

		Year Ended December 31,			Period Ended December 31,			Change from Prior
		2006			2005			Period
Income Tax Expense (Recovery)		$	677,380		$	(29,228	)		2,418	%

The income tax expense for the year ended December 31, 2006 increased 2,418% to $677,380 from a recovery of $29,228 for 2005. The Colombia operations generated a net income before tax of $2.4 million dollars, which resulted in a local income tax liability, offset by income tax assets arising from losses incurred in Argentina.

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Net Income (Loss) Available to Common Shares

		Year Ended December 31,												Period Ended December 31,
		2006												2005												Change from Prior Period
		Argentina			Colombia			Corporate			Total			Argentina			Colombia			Corporate			Total			Argentina			Colombia			Corporate			Total
Net Loss
Net loss (income) before income tax		$	411,028		$	(1,486,075	)	$	6,221,371		$	5,146,324		$	112,445		$	-		$	2,136,463		$	2,248,908			266	%		100	%		191	%		129	%
Income tax												677,380												(29,228	)											-2,418	%
Net Loss											$	5,823,704											$	2,219,680												162	%
Loss per share - Basic and Diluted
Weighted Average Outstanding Common Shares - Basic and Diluted												72,443,501												13,538,149												435	%
Loss per share - Basic and Diluted											$	0.08											$	0.16												-50	%

The net loss for the year ended December 31, 2006 increased 162% to $5,823,704 or $0.08 per share from a loss of $2,219,680, or $0.16 per share in 2005. This loss includes a full year of operating activities at Palmar Largo and six months plus ten days of operations in Colombia, and costs related to the share registration statements. The net loss for the period from incorporation on January 26, 2005 to December 31, 2005 reflect four months of operating activity in Argentina, twelve months of business activity and significant costs relating to the November 10, 2005 share exchange transactions.

Liquidity and Capital Resources

During 2007, we relied upon cash provided by operations and the proceeds of 2006 private placements to fund ongoing operations and our capital investment program. As of December 31, 2007, our cash and cash equivalents balance was $18,188,817 million and our current assets (including cash and cash equivalents balance) less current liabilities were $8,058,049, compared to cash and cash equivalents of $24,100,780 and current assets (including cash and cash equivalents balance) less current liabilities of $14,541,498 million at December 31, 2006. We also have a credit facility with a bank that provides for borrowing in an amount based on the present value of our petroleum reserves, up to a maximum of $50 million, described below.

Effective February 28, 2007, we entered into a credit facility with Standard Bank Plc. The facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of our petroleum reserves up to maximum of $50 million. The initial borrowing base is $7 million and the borrowing base will be re-determined semi-annually based on reserve evaluation reports. As a result of Standard Bank Plc’s review of our Mid-Year 2007 Independent Reserve Audit, we have received preliminary approval to increase our borrowing base to $20 million. The facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base. The facility is secured primarily by our Colombian assets. Under the terms of the facility, we are required to maintain compliance with specified financial and operating covenants. We were required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. As of December 31, 2007, no amounts have been drawn-down under the facility.  In accordance with the terms of the credit facility with Standard Bank Plc, we entered into a costless collar hedging contract for crude oil based on West Texas Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. For the year ended December 31, 2007, we recorded a loss of $3,039,690 on derivative financial instruments.

During the year ended December 31, 2007, we reduced our cash balances by $5,911,963 as compared to an increase in 2006 of $21,879,324. Net cash provided by operating activities for the year ended December 31, 2007 increased to $8,761,439 as compared to $2,010,056 for 2006. The increase was mainly due to the significant increase in oil production and the associated sales price received offset by costs associated with budgeted workovers in both Colombia and Argentina, G&A expenditures associated with increased stewardship costs, including Sarbanes Oxley related expenditures, and securities registration issues, as further explained above in our review of the results of operations. Net cash used in investing activities for the year ended December 31, 2007 decreased 68% to $15,392,705 from $48,206,588 in 2006. During 2007, we expended $15,796,332 (net of changes in non-cash working capital related to capital expenditures of $232,822) in oil and gas property expenditures relating to our drilling and other oilfield activities primarily in Colombia as compared to $10,274,139 (net of changes in non-cash working capital expenditures of $8,026,375) for 2006. In 2006, we expended $36,911,959 related to the purchase of Argosy. Net cash provided by financing activities for the year ended December 31, 2007 was $719,303 as a result of the issuance of common shares upon exercise of warrants. In 2006, net cash provided by financing activities was $68,075,856 mainly as a result of the issuance of common shares through private placements. 

During the year ended December 31, 2006, we increased our cash balances by $21,879,324 and funded our capital expenditures and operating expenditures from proceeds of a series of private placements of our securities. Cash inflows comprised $2,010,056 from operating activities and $68,075,856 from financing activities, offset by cash outflows of $48,206,588 for investing activities. Proceeds from private placements included $75,000,000, less issue costs of $6,303,699, from the sale of 50,000,000 units of our securities in June 2006, $610,000 from the sale of 762,500 units in the first quarter of 2006, and proceeds from the exercise of warrants to purchase common stock. However, of the amount raised, $1,280,951 was held in escrow at December 31, 2006, and the holders of those units had the right to return the units to us and receive their purchase price back under the terms of the escrow agreement because we were unable to obtain a securities laws exemption for those holders by a specified date. At December 31, 2006, we were in discussions with those stockholders regarding whether or not they would exercise that right.

 

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During 2005, we funded the majority of our capital expenditures from funds received through three private placements of our securities. Cash inflows from financing activities were $13,206,116, offset by cash outflows of $2,277,065 from operating activities and $8,707,595 for investing activities. Proceeds from private placements included $11,428,084 from the sale of 14,285,106 units of our securities in the fourth quarter of 2005.

 

Capital expenditures for the year ended December 31, 2006 were $47,186,098 (net of changes in non-cash working capital related to capital expenditures of $8,026,375) and were primarily related to the Argosy purchase in Colombia, the purchase of the El Vinalar and CGC properties in Argentina, development activity at Palmar Largo, drilling activities in Colombia, and office equipment and leasehold improvements in both Calgary and Argentina. During 2005, capital expenditures for the period from incorporation on January 26, 2005 to December 31, 2005, were $8,707,595, predominantly for the acquisition cost of the Palmar Largo, Nacatimbay and Ipaguazu interests in Argentina.

During the year ended December 31, 2007, we spent $15,976,332 (net of changes in non-cash working capital related to capital expenditures of $232,822) on capital projects. During 2007, we drilled seven wells, conducted several workovers of existing wells, and conducted technical studies on our existing acreage.

In Argentina, capital expenditures for the year ended December 31, 2007, were $1,679,305, including $222,932 of accrued expenditures at December 31, 2007. We incurred costs of $659,704 to complete the Puesto Climaco-2 sidetrack well in the Vinalar Block which was drilled in December 2006. Capital expenditures also include the acquisition and reprocessing of seismic in several areas, facility upgrades in Parma Largo and non-cash capitalized stock-based compensation expense.

 

In Colombia, capital expenditures for the year ended December 31, 2007, were $14,214,835, including $7,984,841 of accrued expenditures at December 31, 2007. In Colombia, we drilled six new wells in 2007. We drilled the Laura-1 exploration well in the Talora Block in January 2007, the Caneyes-1 exploration well in the Rio Magdalena Block in February 2007, and the Soyona-1 and Cachapa-1 exploration wells in the Primavera Block in April and March 2007, respectively. These wells were plugged and abandoned. We drilled the Caneyes-1 well at a net cost to us of $1,669,888 and the drilling costs for the three other wells were paid by our partners.

 

We drilled successful wells in the Chaza and Guayayaco areas. We drilled the Juanambu-1 well in March 2007 and encountered hydrocarbon shows in four zones. Testing established the presence of a significant oil accumulation. We drilled and tested the Costayaco-1 well, which also indicated a significant accumulation of oil in a number of zones. Consequently, our proven reserves in Colombia have substantially increased. We put these wells on production in the third quarter of 2007. We drilled the Juanambu-1 and Costayaco-1 wells and commenced drilling of Costayaco-2 for a net cost of $7,598,626. We incurred costs of $4,946,321 on other projects in Colombia during 2007 including $1,673,349 for completion of a 3-D seismic program in Costayaco and $1,162,923 related to a 2-D seismic program in the Rio Magdalena block.

We expect to incur additional development costs as facilities are upgraded in both locations to facilitate production. In addition, we initiated drilling of Costayaco-2 in December 2007 and completed drilling and cased the well in January 2008. We commenced drilling Costayaco-3 in January 2008. We are planning further field development in these areas as a result of the Costayaco and Juanambu discoveries. We completed a new 3-D seismic data acquisition program over the Costayaco structure to optimize positioning of future drilling locations.

 

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In Peru, operations in 2007 included technical studies of Block 122 and Block 128 and the initiation of an aero magnetic and gravity survey over both blocks. This program commenced in the fourth quarter of 2007 and we expect it to be completed in 2008. Expenditures in 2007 were $656,244, with estimated expenditures to complete the work in 2008 of $1.5 million.

Plans for 2008 include the drilling of two exploration wells (at no cost to Gran Tierra Energy) and six development wells (approximately 48% of the cost to be paid by Gran Tierra Energy) in Colombia and one exploration well (50% of the cost to be paid by Gran Tierra Energy) in Argentina along with related facility and pipeline infrastructure for a total capital expenditure budget of $56.8 million. We contemplate several well workovers for wells on existing producing and shut-in fields. In addition to current budgeted projects, we may pursue new ventures in South America, in areas of current activity and in new regions or countries. There is no assurance additional opportunities will be available, or if we participate in additional opportunities that those opportunities will be successful. Based on projected production, prices and costs, we believe that our current operations and capital expenditure program can be maintained from cash flow from existing operations, cash on hand, and our credit facility, barring unforeseen events or a severe downturn in oil and gas prices. Should our operating cash flow decline, we would examine measures such as reducing our capital expenditure program, issuance of debt, or issuance of equity.

Future growth and acquisitions will depend on our ability to raise additional funds through equity, warrant exercises and/or debt markets. During 2005 and 2006 we completed financing initiatives to support acquisition initiatives, which have also brought additional production and cash flow into our company. Increases in the borrowing base under our credit facility are dependent on our success in increasing oil and gas reserves and on future oil prices. Additional funds will be provided to us as holders of our warrants to purchase common shares decide to exercise the warrants.

 

Our initiatives to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities may be affected by the market value of our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing stockholders, and this dilution would be exacerbated by a decline in stock price. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets that are not currently pledged under our existing credit facility.

          

Off-Balance Sheet Arrangements

 

As at December 31, 2007 and 2006, we had no off-balance sheet arrangements.

Contractual Obligations

Gran Tierra Energy holds three categories of operating leases: office, vehicle and housing. We pay monthly costs of $57,638 for office leases, $4,791 for vehicle leases, $9,400 for a compressor and $2,561 for certain employee accommodation leases in Colombia.

We entered into four capital leases in 2006 for office equipment in Calgary, Canada. The leases expire between 2008 and 2011. As of December 31, 2007 capital assets were valued at $21,841 (net of amortization of $17,870). Total rent expense for 2007 was $291,975 (2006 - $221,477; 2005 - $26,904).

Capital lease agreements contain interest rates between 4.75 and 20.5 percent and mature over one to four years. Interest expense incurred under these capital leases to December 31, 2007 was $2,657 (2006 - $2,346).

We have contracted with a third party to provide catering services for our field operations in Colombia. The contract ends January 14, 2009. The remaining contractual commitment is $280,771 to be incurred evenly over the remaining duration of the contract.

We have contracted with a third party to provide a helicopter for field transportation for our Colombia field operations. The contract ends September 30, 2008. The minimum obligation under the contract is for 30 flight hours per month at a rate of $880 per hour. The remaining nine month obligation is $237,600.

Future lease payments and other contractual obligations at December 31, 2007 are as follows:

 

		Payments Due in Period
		Total			Less than 1 year			1-3 Years			3-5 years			more than 5 years
Catering contract obligation		$	280,771		$	269,540		$	11,231		$	-		$	-
Helicopter contract obligation			237,600			237,600			-			-			-
Operating lease obligations			2,581,233			833,799			1,460,629			286,805			-
Capital lease obligations			20,056			9,991			10,065			-			-
Total		$	3,119,660		$	1,350,930		$	1,481,925		$	286,805		$	-

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Critical Accounting Estimates

Use of Estimates

 

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting period.

The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regards to estimates used. Our critical accounting policies and significant judgments and estimates related to those policies are discussed below. We have reviewed these critical accounting policies with the Audit Committee of the Board of Directors.

Oil and Gas Accounting-Reserves Determination

 

We follow the full cost method of accounting for our investment in oil and natural gas properties, as defined by the SEC, as described in note 2 to our consolidated financial statements. Full cost accounting depends on the estimated reserves we believe are recoverable from our oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geo-physical, engineering and economic data.

To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including:

 

	·		expected reservoir characteristics based on geological, geophysical and engineering assessments;
	·		future production rates based on historical performance and expected future operating and investment activities;
	·		future oil and gas quality differentials;
	·		assumed effects of regulation by governmental agencies; and
	·		future development and operating costs.

 

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the US as prescribed by the Society of Petroleum Engineers. Reserve estimates are audited at least annually by independent qualified reserves consultants, Gaffney, Cline & Associates Inc.

Our board of directors oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.

Reserves estimates are critical to many of our accounting estimates, including:

·

Determining whether or not an exploratory well has found economically producible reserves.

 

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	·		Calculating our unit-of-production depletion rates. Proved reserves estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense.
	·		Assessing, when necessary, our oil and gas assets for impairment. Estimated future cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.

Oil and Gas Accounting and Impairment

 

The accounting for and disclosure of oil and gas producing activities requires that we choose between GAAP alternatives. We use the full cost method of accounting for our oil and natural gas operations. Under this method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of proved reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.

 

Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties the costs of which are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter on a country-by-country basis. The ceiling limits these pooled costs to the aggregate of the after-tax, present value, discounted at 10%, of future cash flows attributable to proved reserves, known as the standardized measure, plus the lower of cost or market value of unproved properties less any associated tax effects. Cash flow estimates for our impairment assessments require assumptions about two primary elements — constant prices and reserves. It is difficult to determine and assess the impact of a decrease in our proved reserves on our impairment tests. The relationship between the reserves estimate and the estimated discounted cash flows is complex because of the necessary assumptions that need to be made regarding period end production rates, period end prices and costs. If these capitalized costs exceed the ceiling, we will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expense in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling. Due to the complexity of the calculation, we are unable to provide a reasonable sensitivity analysis of the impact that a reserves estimate decrease would have on our assessment of impairment. A reduction in oil and natural gas prices and/or estimated quantities of oil and natural gas reserves would reduce the ceiling limitation and could result in a ceiling test write-down.

We assessed our oil and gas properties for impairment as at December 31, 2007, 2006 and 2005 and found no impairment write-downs were required based on our assumptions. Estimates of standardized measure of our future cash flows from proved reserves were based on realized crude oil prices of $90.01 in Colombia and $42.00 for our Argentina properties as at December 31, 2007. A future reduction in oil prices and/or quantities of proved reserves would reduce the ceiling limitation and may result in a ceiling test write-down.

Asset Retirement Obligations

 

We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future asset retirement obligations requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.

We record asset retirement obligations in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities and chemical plants. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and expected changes in legal, regulatory, environmental and political environments. The asset retirement obligations we have recorded result in an increase to the carrying cost of our property, plant and equipment. The obligations are accreted with the passage of time. A change in any one of our assumptions could impact our asset retirement obligations, our property, plant and equipment and our net income.

 

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It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results. We are confident, however, that our assumptions are reasonable.

Goodwill

 

Goodwill represents the excess of purchase price of business combinations over the fair value of net assets acquired and we test for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. We estimate the fair value of each reporting unit and compare it to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, we write down the goodwill to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for our reporting units, we estimate the fair values of the reporting units based upon estimated future cash flows of the reporting unit. The goodwill on our financial statements was a result of the Argosy acquisition, and relates entirely to the Colombia reporting segment.

Deferred Income Taxes

 

We follow the liability method of accounting for income taxes whereby we recognize future income tax assets and liabilities based on temporary differences in reported amounts for financial statement and tax purposes. We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.

To assess the realization of deferred tax assets, management considers whether it is more likely than not that 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. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. As of December 31, 2007, we had no deferred tax assets for which management considers realization is more likely than not.

Share-Based Payment Arrangements  

 

We record share-based payment arrangements in accordance with SFAS 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options based on estimated fair values.

  

SFAS 123R requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations.

 

Under SFAS 123R, share-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Compensation expense is recognized using the accelerated method. As share-based compensation expense recognized in the Consolidated Statements of Operations is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

 

Under SFAS 123 R, we utilized a Black-Scholes option pricing model to measure the fair value of stock options granted to employees. Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, our expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors.

 

Option-pricing models were developed for use in estimating the value of traded options that have no vesting or hedging restrictions and are fully transferable. Because (1) our employee stock options have certain characteristics that are significantly different from traded options, and (2) changes in the subjective assumptions can materially affect the estimated value, in management’s opinion, the existing valuation models may not provide an accurate measure of the fair value of our employee stock options. Although the fair value of employee stock options is determined in accordance with SFAS No. 123R using a Black-Scholes option-pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. We are responsible for determining the assumptions used in estimating the fair value of its share-based payment awards.

 

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Warrants

 

We follow the fair-value method of accounting for warrants issued to purchase our common stock. The change of $8.6 million in the fair value of warrants issued in the 2006 Offering, arising from the amendment to the terms of the warrants in connection with the settlement of the liability for liquidated damages, was determined using a Black-Scholes warrant pricing model based on a 25% volatility rate, which reflects a typical volatility rate used to value this type of financial instrument.

New Accounting Pronouncements

In July 2006, the FASB issued FIN 48 (FASB Interpretation Number) Accounting for Uncertainty in Income Taxes with respect to FAS 109 Accounting for Income Taxes regarding accounting for and disclosure of uncertain tax positions. This guidance seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation requires that we recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resulting from the change in accounting principle is to be recorded as an adjustment to the opening balance of accumulated deficit. This interpretation is effective for fiscal years beginning after December 15, 2006 and its adoption on January 1, 2007 did not have a material impact on our consolidated financial statements and did not require us to record any amounts in the financial statements.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value under US generally accepted accounting principles and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. The provisions of SFAS 157 are to be applied prospectively, except for the initial impact in certain situations, which are required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In December 2006, the FASB issued Staff Position (FSP) EITF 00-19-2, Accounting for Registration Payment Arrangements. FSP EITF 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with SFAS No. 5, Accounting for Contingencies. This FSP is effective for fiscal years beginning after December 15, 2006. We early adopted this FSP during the year ended December 31, 2006 and recorded $1,258,065 in liquidated damages as an expense in the consolidated statement of operations and deficit and the same amount in accrued liabilities at December 31, 2006. For the year ended December 31, 2007, we expensed an additional amount of $7,366,949. As at December 31, 2007, we had an accumulated expense for liquidated damages of $8,625,014. Pursuant to an amendment of terms of Registration Rights Payments with respect to the associated shareholder agreement, our shareholders waived the right to settle the liquidated damages in cash and in lieu agreed to an amendment of the exercise price of the warrants from $1.75 to $1.05 on June 27, 2007, and an extension of one year in the term for the warrants. The settlement of the liquidated damages is reflected as an increase to the value of the warrants included in the shareholders’ equity section of the consolidated balance sheet.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS 159 permits an entity to elect fair value as the initial and subsequent measurement attribute for many financial assets and liabilities. Entities electing the fair value option would be required to recognize changes in fair value in earnings. Entities electing the fair value option are required to distinguish on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. SFAS 159 is effective for our fiscal year 2008. The adjustment to reflect the difference between the fair value and the carrying amount would be accounted for as a cumulative-effect adjustment to retained earnings as of the date of initial adoption. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In December 2007, the FASB issued SFAS 141 (R), “Business Combinations”, and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements”. SFAS 141 (R) requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141 (R) and SFAS 160 are effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited and the provisions are applied prospectively. We have not yet determined the effect on our consolidated financial statements, if any, upon adoption of SFAS 141 (R) or SFAS No. 160.

 

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Our principal market risk relates to oil prices. We have not hedged these risks in the past. Essentially 100% of our revenues are from oil sales at prices which are defined by contract relative to West Texas Intermediate and adjusted for transportation and quality, for each month. In Argentina, a further discount factor which is related to a tax on oil exports establishes a common pricing mechanism for all oil produced in the country, regardless of its destination.

In accordance with the terms of the credit facility with Standard Bank Plc, which we entered into on February 28, 2007, we entered into a costless collar hedging contract for crude oil based on West Texas Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. At December 31, 2007, the value of this costless collar was a loss of $2,648,346. A hypothetical 10% increase in WTI price on December 31, 2007 would cause the loss to increase by approximately $1,475,168, and a hypothetical 10% decrease in WTI price on December 31, 2007 would cause the loss to decrease by approximately $1,258,675.

We consider our exposure to interest rate risk to be immaterial. Interest rate exposures relate entirely to our investment portfolio, as we do not have short-term or long-term debt. However, if we draw down amounts under our credit facility with Standard Bank Plc, we will incur interest rate risk with respect to the amounts drawn down and outstanding. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates. We do not hold any of these investments for trading purposes. We do not hold equity investments.

Foreign currency risk is a factor for our company but is ameliorated to a large degree by the nature of expenditures and revenues in the countries where we operate. We have not engaged in any formal hedging activity with regard to foreign currency risk. Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. price of West Texas intermediate oil. In Colombia, we receive 75% of oil revenues in U.S. dollars and 25% in Colombian pesos at current exchange rates. The majority of our capital expenditures in Colombia are in U.S. dollars and the majority of local office costs are in local currency. As a result, the 75%/25% allocation between U.S. dollar and peso denominated revenues is approximately balanced between U.S. and peso expenditures, providing a natural currency hedge. In Argentina, reference prices for oil are in U.S. dollars and revenues are received in Argentine pesos according to current exchange rates. The majority of capital expenditures within Argentina have been in U.S. dollars with local office costs generally in pesos. While we operate in South America exclusively, the majority of our spending since our inauguration has been for acquisitions. The majority of these acquisition expenditures have been valued and paid in U.S. dollars.

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Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Chartered Accountants

To the Board of Directors and Shareholders of Gran Tierra Energy Inc.

We have audited the accompanying consolidated balance sheets of Gran Tierra Energy Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the two years then ended, and for the period from incorporation on January 26, 2005 to December 31, 2005. 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 Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). 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 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, these consolidated financial statements present fairly, in all material respects, the financial position of Gran Tierra Energy Inc. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the two years then ended and for the period from incorporation on January 26, 2005 to December 31, 2005 in accordance with accounting principles generally accepted in the United States of America.

 

As discussed in Note 13, the accompanying 2007 and 2006 consolidated financial statements have been restated. We therefore withdraw our previous report dated March 7, 2008 on those financial statements, as originally filed.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2008 (May 12, 2008 as to the effects of the material weakness), expressed an adverse opinion on the Company’s internal control over financial reporting because of a material weakness.

 

/s/ Deloitte & Touche LLP

Independent Registered Chartered Accountants

Calgary, Canada

March 7, 2008  (May 12, 2008 as to the effects of the restatement discussed in Note 13)

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Consolidated Statements of Operations and Accumulated Deficit

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

 

		Period Ended December 31,
		2007			2006			2005
		(Expressed in U.S. dollars)
REVENUE AND OTHER INCOME
Oil sales		$	31,807,641		$	11,645,553		$	946,098
Natural gas sales			44,971			75,488			113,199
Interest			425,542			351,872			—
			32,278,154			12,072,913			1,059,297
EXPENSES
Operating			10,474,368			4,233,470			395,287
Depletion, depreciation and accretion			9,414,907			4,088,437			462,119
General and administrative			10,231,952			6,998,804			2,482,070
Liquidated damages			7,366,949			1,527,988			—
Derivative financial instruments			3,039,690			—			—
Foreign exchange (gain) loss			(77,275	)		370,538			(31,271	)
			40,450,591			17,219,237			3,308,205
LOSS BEFORE INCOME TAX			(8,172,437	)		(5,146,324	)		(2,248,908	)
Income tax			(294,767	)		(677,380	)		29,228
NET LOSS AND COMPREHENSIVE LOSS		$	(8,467,204	)	$	(5,823,704	)	$	(2,219,680	)
ACCUMULATED DEFICIT, beginning of period			(8,043,384	)		(2,219,680	)		—
ACCUMULATED DEFICIT, end of period		$	(16,510,588	)	$	(8,043,384	)	$	(2,219,680	)
NET LOSS PER COMMON SHARE — BASIC & DILUTED			(0.09	)		(0.08	)		(0.16	)
Weighted average common shares outstanding — basic & diluted			95,096,311			72,443,501			13,538,149

 

(See notes to the consolidated financial statements)

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Consolidated Balance Sheets

 

		Year Ended December 31,
		2007			2006
		(Expressed in U.S. dollars)
ASSETS
Current assets
Cash and cash equivalents		$	18,188,817		$	24,100,780
Restricted cash			—			2,291,360
Accounts receivable			10,694,705			5,089,561
Inventory			786,921			811,991
Taxes receivable			1,177,076			404,120
Prepaids			442,271			676,524
Deferred tax asset (Note 8)			220,000			—
Total Current Assets			31,509,790			33,374,336
Oil and gas properties, using the full cost method of accounting
Proved			44,292,203			37,760,230
Unproved			18,910,229			18,333,054
Total Oil and Gas Properties			63,202,432			56,093,284
Other assets			715,470			614,104
Total Property, Plant and Equipment (Note 5)			63,917,902			56,707,388
Long term assets
Deferred tax asset (Note 8)			1,838,436			444,324
Taxes receivable			525,350			—
Other long-term assets			—			5,826
Goodwill			15,005,083			15,005,083
Total Long Term Assets			17,368,869			15,455,233
Total Assets		$	112,796,561		$	105,536,957
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable (Note 9)		$	11,327,292		$	6,729,839
Accrued liabilities (Note 9)			6,138,684			8,932,966
Liquidated damages			—			1,527,988
Derivative financial instruments (Note 11)			1,593,629			—
Current taxes payable			3,284,334			1,642,045
Deferred tax liability (Note 8)			1,107,802			—
Total Current Liabilities			23,451,741			18,832,838
Long term liabilities			131,821			39,077
Deferred tax liability (Note 8)			9,234,926			7,153,112
Deferred remittance tax			1,332,016			2,722,545
Derivative financial instruments (Note 11)			1,054,716			—
Asset retirement obligation (Note 7)			799,486			594,606
Total Long Term Liabilities			12,552,965			10,509,340
Shareholders’ equity
Common shares (Note 6)			95,176			95,455
(80,389,676 and 78,789,104 common shares and 14,787,303 and 16,666,661 exchangeable shares, par value $0.001 per share, issued and outstanding as at December 31, 2007 and 2006, respectively)
Additional paid in capital			72,457,519			71,311,155
Warrants			20,749,748			12,831,553
Accumulated deficit			(16,510,588	)		(8,043,384	)
Total Shareholders’ Equity			76,791,855			76,194,779
Total Liabilities and Shareholders’ Equity		$	112,796,561		$	105,536,957

 

(See notes to the consolidated financial statements)

 

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Consolidated Statements of Cash Flow

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005 

 

		Period Ended December 31,
		2007			2006			2005
		(Expressed in U.S. dollars)
Operating Activities		(As Restated -see note 13)			(As Restated -see note 13)
Net loss		$	(8,467,204	)	$	(5,823,704	)	$	(2,219,680)	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion			9,414,907			4,088,437			462,119
Deferred tax			(702,827	)		892,998			(29,228	)
Stock based compensation			809,522			260,495			52,911
Liquidated damages			5,838,961			1,527,988			—
Unrealized loss on financial instruments			2,648,346			—			—
Net changes in non-cash working capital
Accounts receivable			(5,605,144	)		(4,280,601	)		(808,960	)
Inventory			25,070			(364,983	)		(447,012	)
Prepaids and other current assets			234,253			(633,823	)		(42,701	)
Deferred tax asset			(220,000	)		—			—
Accounts payable and accrued liabilities			2,808,420			6,639,230			1,264,052
Taxes receivable and payable			869,333			(295,981	)		(108,139	)
Deferred tax liability			1,107,802			—			—
Net cash provided by (used in) operating activities			8,761,439			2,010,056			(1,876,638	)
Investing Activities
Restricted cash			1,010,409			(1,020,490	)		(400,427	)
Oil and gas property expenditures			(15,976,332	)		(10,274,139	)		(8,707,595	)
Business acquisition			—			(36,911,959	)		—
Long term assets and liabilities			(426,782	)		—			—
Net cash used in investing activities			(15,392,705	)		(48,206,588	)		(9,108,022	)
Financing Activities
Restricted cash			—			(1,280,993	)		—
Proceeds from issuance of common stock			719,303			69,356,849			13,206,116
Net cash provided by financing activities			719,303			68,075,856			13,206,116
Net (decrease) increase in cash and cash equivalents			(5,911,963	)		21,879,324			2,221,456
Cash and cash equivalents, beginning of period			24,100,780			2,221,456			—
Cash and cash equivalents, end of period		$	18,188,817		$	24,100,780		$	2,221,456
Supplemental cash flow disclosures:
Cash paid for interest		$	80,234		$	104,307		$	—
Cash paid for taxes		$	116,140		$	741,380		$	—
Non-cash investing activities:
Accounts payable related to capital additions		$	8,259,197		$	8,026,375		$	—

 

(See notes to the consolidated financial statements)

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Consolidated Statement of Shareholders’ Equity

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

 

		Period Ended December 31,
		2007			2006			2005
		(Expressed in U.S. dollars)
Share Capital
Balance beginning of period		$	95,455		$	43,285		$	—
Issue of common shares			670			52,170			43,285
Cancelled common shares			(949	)		—			—
Balance End of Period		$	95, 176		$	95,455		$	43,285
Additional Paid-in-Capital
Balance beginning of period		$	71,311,155		$	11,807,313		$	—
Cancelled common shares			(1,086,213	)		—			—
Issue of common shares			718,633			59,190,356			11,754,402
Exercise of warrants			513,030			52,991			—
Stock based compensation expense			1,000,914			260,495			52,911
Balance end of period		$	72,457,519		$	71,311,155		$	11,807,313
Warrants
Balance beginning of period		$	12,831,553		$	1,408,429		$	—
Cancelled warrants			(232,548	)		—			—
Issue of warrants			8,625,014			11,476,115			1,408,429
Exercise of warrants			(474,271	)		(52,991	)		—
Balance end of period		$	20,749,748		$	12,831,553		$	1,408,429
Accumulated Deficit
Balance beginning of period		$	(8,043,384	)	$	(2,219,680	)	$	—
Net loss			(8,467,204	)		(5,823,704	)		(2,219,680	)
Balance end of period		$	(16,510,588	)	$	(8,043,384	)	$	(2,219,680	)
Total Shareholders’ Equity		$	76,791,855		$	76,194,779		$	11,039,347

 

(See notes to the consolidated financial statements)

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Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

1. Description of Business

 

Gran Tierra Energy Inc., a Nevada corporation (the “Company” or “Gran Tierra Energy”) is a publicly traded oil and gas company engaged in acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Argentina, Colombia and Peru.

     

2. Significant Accounting Policies

 

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting period. The Company believes that the information and disclosures presented are adequate to ensure the information presented is not misleading.

Significant accounting policies are:

Basis of consolidation

 

These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.

Use of estimates

 

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and changes from those estimates are recorded when known. Oil and natural gas reserves and related present value of future cash flows, impairment assessments, stock option expense, income taxes, asset retirement obligation, derivative instrument valuation, legal and environmental risks and exposures and any assumptions associated with valuation of oil and gas property are all subject to estimation in the Company’s financial results.

Foreign currency translation

 

The functional currency of the Company, including its subsidiaries in Argentina, Colombia and Peru, is the United States dollar. Monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred. Depreciation or amortization of assets is translated at the historical exchange rates similar to the assets to which they relate.

 

Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are included in the consolidated statement of operations and deficit.

Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

 

The evaluation of a tax position in accordance with FIN 48 (FASB Interpretation Number) Accounting for Uncertainty in Income Taxes with respect to SFAS 109 Accounting for Income Taxes is a two-step process. The first step is recognition: The Company determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is measurement: A tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense in the consolidated statement of operations. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future.

The Company calculates two taxes for its business activities in Argentina. First, a minimum presumed income is calculated by applying a one percent tax rate to taxable assets as of the end of the period. If the tax on minimum presumed income exceeds income tax payable during the year, the excess is considered a prepayment of future income taxes due over the next ten year period. Secondly, a ‘third party tax substitutable’ is recorded. The government ensures each company, with foreign ownership, withholds taxes based on the assumption that profits will be transferred to the owners. If profits are not transferred, the taxes paid may be used to offset tax liabilities in the future.

Loss per share

 

Basic loss per share calculations are based on the loss attributable to common shareholders for the period divided by the weighted average number of common shares issued and outstanding during the period. The diluted loss per share calculation is based on the weighted average number of common shares outstanding during the period, plus the effects of dilutive common share equivalents. This method requires that the dilutive effect of outstanding options and warrants issued should be calculated using the treasury stock method. This method assumes that all common share equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase common shares of the Company at the average trading price of common shares during the period. At December 31, 2007 and 2006, 5,724,168 and 2,700,000 options to purchase common shares and warrants to purchase 33,917,536 and 35,156,915 common shares, respectively, were excluded from the diluted loss per share calculation as the instruments were anti-dilutive.

Stock-based compensation

 

The Company follows the fair-value method of accounting for stock options granted to directors, officers and employees pursuant to Financial Accounting Standards Board Statement 123 (Revised). Stock-based compensation expense is included as part of oil and natural gas properties, operating and general and administrative expenses with a corresponding increase to contributed surplus. Compensation expense for options granted is based on the estimated fair value at the time of grant and the expense is recognized over the requisite service period of the option.

Accounting for Oil and Gas Derivative Instruments

 

The Company follows the provisions of SFAS No.133,“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of SFAS 133, the Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge as noted above. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge are recognized in the statement of operations along with the changes in fair value of the hedged item attributable to the hedged risk. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as derivative financial instrument gain or loss. The Company’s derivative instruments currently do not qualify as either a fair value hedge or a cash flow hedge.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

 

Warrants

 

The Company follows the fair-value method of accounting for warrants issued to purchase its common stock. The change of $8.6 million in the fair value of warrants issued in the 2006 Offering, arising from the amendment to the terms of the warrants in connection with the settlement of the liability for liquidated damages, was determined using a Black-Scholes warrant pricing model based on a 25% volatility rate, which reflects a typical volatility rate used to value this type of financial instrument.

New Accounting Pronouncements

 

In July 2006, the FASB issued FIN 48 Accounting for Uncertainty in Income Taxes with respect to SFAS 109 Accounting for Income Taxes regarding accounting for and disclosure of uncertain tax positions. This guidance seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation requires that the Company recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resulting from the change in accounting principle is to be recorded as an adjustment to the opening balance of accumulated deficit. This interpretation is effective for fiscal years beginning after December 15, 2006 and its adoption on January 1, 2007 did not have a material impact on the Company’s consolidated financial statements and did not require the Company to record any amounts in the financial statements.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value under US generally accepted accounting principles and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. The provisions of SFAS 157 are to be applied prospectively, except for the initial impact in certain situations, which are required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption. The Company does not expect the adoption of this statement will have a material impact on its results of operations or financial position.

In December 2006, the FASB issued Staff Position (FSP) EITF 00-19-2, Accounting for Registration Payment Arrangements. FSP EITF 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with SFAS 5, Accounting for Contingencies. This FSP is effective for fiscal years beginning after December 15, 2006. The Company early adopted this FSP during the year ended December 31, 2006 and recorded $1,258,065 in liquidated damages as an expense in the consolidated statement of operations and deficit and the same amount in accrued liabilities at December 31, 2006. For the year ended December 31, 2007 the Company expensed an additional amount of $7,366,949. As at December 31, 2007, the Company had an accumulated expense for liquidated damages of $8,625,014. Pursuant to an amendment of terms of Registration Rights Payments with respect to the associated shareholder agreement, the Company’s shareholders waived the right to settle the liquidated damages in cash and in lieu agreed to an amendment of the exercise price of the warrants from $1.75 to $1.05 on June 27, 2007, and an extension of one year in the term for the warrants. The settlement of the liquidated damages is reflected as an increase to the value of the warrants included in the shareholders’ equity section of the consolidated balance sheet.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS 159 permits an entity to elect fair value as the initial and subsequent measurement attribute for many financial assets and liabilities. Entities electing the fair value option would be required to recognize changes in fair value in earnings. Entities electing the fair value option are required to distinguish on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. SFAS 159 is effective for the Company’s fiscal year 2008. The adjustment to reflect the difference between the fair value and the carrying amount would be accounted for as a cumulative-effect adjustment to retained earnings as of the date of initial adoption. The Company does not expect the adoption of this statement will have a material impact on its results of operations or financial position.

In December 2007, the FASB issued SFAS 141 (R), “Business Combinations”, and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements”. SFAS 141 (R) requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141 (R) and SFAS 160 are effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited and the provisions are applied prospectively. The Company has not yet determined the effect on our consolidated financial statements, if any, upon adoption of SFAS 141 (R) or SFAS No. 160.

3. Business Combination

 

Gran Tierra Energy entered into a Securities Purchase Agreement dated May 25, 2006 with Crosby Capital LLC (“Crosby”) to acquire all of the limited partnership interests of Argosy Energy International (“Argosy) and all of the issued and outstanding capital stock of Argosy Energy Corp. On June 20, 2006 Gran Tierra Energy closed the Argosy acquisition and paid consideration to Crosby consisting of $37.5 million cash, 870,647 shares of the Company’s common stock and overriding and net profit interests in certain of Argosy’s assets valued at $1 million. The value of the overriding and net profit interests was based on the present value of expected future cash flows. All of Argosy Energy International’s assets are in Colombia.

The acquisition has been accounted for using the purchase method, and the results of Argosy Energy International have been consolidated with Gran Tierra Energy from June 20, 2006. The following table shows the allocation of the purchase price based on the fair values of the assets and liabilities acquired:

Cash paid (net of cash acquired)		$	36,414,385
Common shares issued			1,305,971
Transaction costs			497,574
Total purchase price		$	38,217,930
Purchase Price Allocated:
Oil and natural gas assets		$	32,553,211
Goodwill (1)			15,005,083
Accounts receivable			5,361,887
Inventories (2)			567,355
Long term investments			6,772
Accounts Payable and Accrued Liabilities			(6,085,109	)
Long term liabilities			(49,763	)
Deferred tax liabilities			(9,141,506	)
Total purchase price allocated		$	38,217,930

(1)		Goodwill is not deductible for tax purposes.
(2)		Inventory is comprised of $497,000 supplies and $70,000 of oil inventory.

 

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

The pro forma results for the period ended December 31, 2005 and December 31, 2006 are shown below, as if the acquisition had occurred on January 26, 2005 and January 1, 2006. Pro forma results are not indicative of actual results or future performance.

		December 31,
		2006			2005
Revenue		$	18,775,357		$	12,950,000
Net income			294,105			1,569,000
Earnings per share (Basic)		$	0.01		$	0.04
Earnings per share (Diluted)		$	0.01		$	0.03

4. Segment and Geographic Reporting

 

The Company’s reportable operating segments are Argentina and Colombia. The Company is primarily engaged in the exploration and production of oil and natural gas. Peru is not a reportable segment because the level of activity on these land holdings is insignificant at this time and is included as part of the Corporate balances. The accounting policies of the reportable operating segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and natural gas operations before price risk management and income taxes.

The Colombia assets were acquired on June 20, 2006, and the Argentina assets were acquired on September 1, 2005. Therefore the comparable segmented information for 2005 includes only four months of operations for Argentina, and there is no comparable 2005 information for Colombia.

 

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

 

The following tables present information on the Company’s reportable geographic segments:

Gran Tierra Energy Inc. Year Ended December 31, 2007
		Corporate			Colombia			Argentina			Total
Revenues		$	—		$	23,748,155		$	8,104,457		$	31,852,612
Interest income			187,532			222,785			15,225			425,542
Depreciation, depletion & accretion			87,987			6,850,086			2,476,834			9,414,907
Segment income (loss) before income tax			(17,181,895	)		11,484,448			(2,474,990	)		(8,172,437	)
Segment capital expenditures		$	731,281		$	14,214,835		$	1,679,305		$	16,625,421
		Year Ended December 31, 2006
			Corporate			Colombia			Argentina			Total
Revenues		$	—		$	6,612,190		$	5,108,851		$	11,721,041
Interest income			351,872			—			—			351,872
Depreciation, depletion & accretion			43,576			2,494,317			1,550,544			4,088,437
Segment income (loss) before income tax			(6,221,372	)		1,486,075			(411,027	)		(5,146,324	)
Segment capital expenditures		$	256,482		$	34,053,289		$	14,084,410		$	48,394,181
		Period Ended December 31, 2005
			Corporate			Colombia			Argentina			Total
Revenues		$	—		$	—		$	1,059,297		$	1,059,297
Depreciation, depletion & accretion			9,097			—			453,022			462,119
Segment income (loss) before income tax			(2,136,463	)		—			(112,445	)		(2,248,908	)
Segment capital expenditures		$	131,200		$	—		$	8,182,008		$	8,313,208

		Year Ended December 31, 2007
		Corporate			Colombia			Argentina			Total
Property, plant & equipment		$	1,030,976		$	43,638,837		$	19,248,089		$	63,917,902
Goodwill			—			15,005,083			—			15,005,083
Other assets			11,302,705			15,949,418			6,621,453			33,873,576
Total		$	12,333,681		$	74,593,338		$	25,869,542		$	112,796,561
		Year Ended December 31, 2006
			Corporate			Colombia			Argentina			Total
Property, plant & equipment		$	387,682		$	36,274,088		$	20,045,618		$	56,707,388
Goodwill			—			15,005,083			—			15,005,083
Other assets			13,242,859			9,878,443			10,703,184			33,824,486
Total		$	13,630,541		$	61,157,614		$	30,748,802		$	105,536,957

The Company’s revenues are derived principally from uncollaralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. In 2007, the Company has one significant customer for its Colombian crude oil, Ecoptrol S.A., a Colombian government agency. In Argentina, the Company has one significant customer, Refineria del Norte S.A.

65

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

5. Property, Plant and Equipment

		As at December 31, 2007									As at December 31, 2006
		Cost			Accumulated DD&A			Net book value			Cost			Accumulated DD&A			Net book value
Oil and natural gas properties
Proven		$	57,832,454		$	(13,540,251	)	$	44,292,203		$	41,191,274		$	(3,431,044	)	$	37,760,230
Unproven			18,910,229			—			18,910,229			18,333,054			—			18,333,054
Furniture and fixtures			815,333			(559,481	)		255,852			289,353			(47,637	)		241,716
Computer equipment			718,540			(299,195	)		419,345			912,645			(592,646	)		319,999
Automobiles			71,695			(31,422	)		40,273			69,499			(17,110	)		52,389
Total capital assets		$	78,348,251		$	(14,430,349	)	$	63,917,902		$	60,795,825		$	(4,088,437	)	$	56,707,388

The Company has capitalized $1,690,937 (2006 - $138,383) of general and administrative expenses directly related to the Colombian full cost center including $138,779 of stock-based compensation expense and $167,372 (2006 - $3,921) of general and administrative expenses in the Argentina full cost center which includes $52,613 of stock-based compensation.

The unproven oil and natural gas properties consist of exploration lands held in Colombia, Argentina and Peru. The Company has $15.1 million in unproved assets in Colombia, $3.1 million of unproved assets in Argentina and $0.7 million of unproved assets in Peru. These properties are being held for their exploration value and are not being depleted pending determination of existence of estimated proved reserves. Gran Tierra Energy will continue to assess and allocate the unproven properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.

The following is a summary of Gran Tierra Energy’s oil and natural gas properties not subject depletion as of December 31, 2007

 

		Costs Incurred in
		2007			2006			Total
Acquisition costs - Argentina		$	—		$	3,148,206		$	3,148,206
Acquisition costs - Colombia			—			11,418,956			11,418,956
Exploration costs - Peru			656,244			—			656,244
Exploration costs - Colombia			807,670			—			807,670
Development costs - Colombia			2,879,153			—			2,879,153
Total oil and natural gas properties not subject to depletion		$	4,343,067		$	14,567,162		$	18,910,229

6. Share Capital

Share capital

 

The Company’s authorized share capital consists of 325,000,001 shares of our capital stock, of which 300 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share (collectively, “common stock”), and 1 share designated as special voting stock, par value $0.001 per share. Outstanding share capital consists of 80,389,676 common voting shares of the Company and 14,787,303 exchangeable shares of Goldstrike Exchange Co. Each exchangeable share is exchangeable only into one common voting share of the Company. The holders of common stock are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the board of directors, in its discretion, declares from legally available funds. The holders of common stock have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the common stock. Holders of exchangeable shares have the same rights as holders of common voting shares.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

 

During the second quarter of 2007, investors holding 948,853 units, comprising 948,853 common shares and warrants to purchase 474,427 common shares, exercised their right to have the Company return to them the purchase price for the securities held in escrow. The funds of $1,280,951, held in escrow by the Bank of America were refunded to the investors to complete this transaction during June, 2007, and the units were cancelled.

Warrants

 

At December 31, 2007, the Company had 14,442,622 warrants outstanding to purchase 7,221,311 common shares for $1.25 per share and 53,392,450 warrants outstanding to purchase 26,696,225 common shares for $1.05 per share.

In connection with settlement of liquidated damages relating to a delay in registration of units issued in June 2006, as described in the “Registration Rights Payments” section below, the Company amended the terms of the warrants issued to stockholders in June 2006 by adjusting the exercise price from $1.75 to $1.05 and extending the term of the warrants by one year to June 2012.

Registration Rights Payments

 

The shares and warrants have registration rights associated with their issuance pursuant to which the Company agreed to register for resale the shares and warrants. In the event that the registration statements were not declared effective by the SEC by specified dates, the Company was required to pay liquidated damages to the purchasers of the share and warrants.

The 15,047,606 units issued in the fourth quarter of 2005 and first quarter of 2006 had liquidated damages payable in the amount of 1% of the purchase price for each unit per month payable each month the registration statement was not declared effective beyond the mandatory effective date (July 10^th, 2006). The total amount recorded at December 31, 2006, for these liquidated damages was $269,923. There are no further liabilities associated with these shares. As of February 14, 2007, the first registration statement was declared effective by the SEC.

 

In June, 2006, the Company sold an aggregate of 50 million units of its securities at a price of $1.50 per unit in a private offering for gross proceeds of $75 million, pursuant to three separate Securities Purchase Agreements, dated June 20, 2006, and one Securities Purchase Agreement, dated June 30, 2006 (collectively, the “2006 Offering”). Each unit comprised one share of Gran Tierra Energy’s common stock and one warrant to purchase one-half of a share of Gran Tierra Energy’s common stock at an exercise price of $1.75 for a period of five years, resulting in the issuance of 50 million shares of Gran Tierra Energy’s common stock. In connection with the issuance of these securities, Gran Tierra Energy entered into four separate Registration Rights Agreements with the investors pursuant to which Gran Tierra Energy agreed to register for resale the shares and warrants (and shares issuable pursuant to the warrants) issued to the investors in the offering by November 17, 2006. The second registration statement was declared effective by the SEC on May 14, 2007. Gran Tierra Energy had accrued $8.6 million in liquidated damages as of that date.

On June 27, 2007, under the terms of the Registration Rights Agreements, the Company obtained a sufficient number of consents from the signatories to the agreements waiving Gran Tierra Energy’s obligation to pay in cash the accrued liquidated damages. The Company agreed to amend the terms of the warrants issued in the 2006 Offering by reducing the exercise price of the warrants to $1.05 and extending the life of the warrants by one year, in lieu of a cash payment for liquidated damages. The revised fair value of the warrants was determined using a Black-Scholes warrant pricing model based on a 25% volatility rate, which reflects a typical volatility rate used to value this type of financial instrument. The $8,625,014 of liquidated damages has been recorded as an expense in the consolidated statement of operations in the amounts of $7,366,949 million for the year ended December 31, 2007, and $1,258,065 million in the fourth quarter of 2006, with a corresponding liability recorded on the consolidated balance sheet. The revision in the fair value of the warrants resulting from the amendment to the terms of the warrants amounted to $8,625,014 (equivalent to the amount of the liquidated damages) and has been reflected on the consolidated balance sheet as an increase to the warrant value included in shareholders’ equity and a settlement of the liability for liquidated damages.

 

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

Stock options

 

As December 31, 2007, the Company has a 2007 Equity Incentive Plan, formed through the approval by shareholders of the amendment and restatement of the 2005 Equity Incentive Plan, under which the Company’s board of directors is authorized to issue options or other rights to acquire up to 9,000,000 shares of the Company’s common stock.

The Company has granted options to purchase common shares to certain directors, officers, employees and consultants. Each option permits the holder to purchase one common share at the stated exercise price. The options vest over three years and have a term of ten years, or the grantees end of service to the Company, which ever occurs first. At the time of grant, the exercise price equals the market price. The following options have been granted:

 

		Number of			Weighted Average
		Outstanding			Exercise Price
		Options			$/Option
Outstanding, December 31, 2006			2,700,000		$	1.07
Granted in 2007			3,372,501		$	1.87
Forfeited in 2007			(348,333	)	$	(1.57	)
Outstanding, December 31, 2007			5,724,168		$	1.52

The weighted average grant date fair value for options granted in 2007 was $1.10 (2006 - $0.84; 2005 - $0.20)

The table below summarizes stock options outstanding at December 31, 2007:

		Number of			Weighted Average			Weighted
		Outstanding			Exercise Price			Average
Range of Exercise Prices ($/option)		Options			$/Option			Expiry Years
$0.80			1,311,668		$	0.80			7.9
$1.19 to $1.29			1,890,000		$	1.26			9.0
$1.72			385,000		$	1.72			9.9
$2.14			2,137,500		$	2.14			10.0
Total			5,724,168		$	1.52			9.2

 

The aggregate intrinsic value of options outstanding at December 31, 2007 is $6,334,036 based on the Company’s closing stock price of $2.62 for that date. At December 31, 2007, there was $2,927,266 of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next 3 years.

The table below summarizes exercisable stock options at December 31, 2007:

		Number of			Weighted Average			Weighted
		Exercisable			Exercise Price			Average
Range of Exercise Prices ($/option)		Options			$/Option			Expiry Years
$0.80			892,501		$	0.80			7.9
$1.19 to $1.27			351,666		$	1.27			8.9
Total			1,244,167		$	0.93			8.1

 

The weighted average grant date fair value for options vested in 2007 was $0.49 (2006 - $0.10). The aggregate intrinsic value of options exercisable at December 31, 2007 is $3,259,718 based on the Company’s closing stock price of $2.62 for that date.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

In 2007, the stock-based compensation expense is $1,000,914 (2006 - $260,495; 2005 - $52,911) of which $737,010 (2006- $260,495; 2005 - $52,911) has been recorded in general and administrative expense and $72,513 has been recorded in operating expense in the consolidated statement of operations. In 2007, $191,391 was capitalized as part of exploration and development costs.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table. The Company uses historical data to estimate option exercises, expected term and employee departure behavior used in the Black-Scholes option pricing model. Expected volatilities used in the fair value estimate are based on historical volatility of the Company’s stock. The risk-free rate for periods within the contractual term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.

		2007			2006			2005
Dividend yield ($  per share)		$	nil		$	nil		$	nil
Volatility (%)			93.8% to 103.5	%		104.5	%		nil
Risk-free interest rate (%)			3.5% to 5.06	%		5.1	%		4.3	%
Expected term (years)			3 years			3 years			3 years
Forfeiture percentage (% per year)			10	%		10	%		10	%

7. Asset Retirement Obligation

The December 31, 2007 asset retirement obligation is comprised of a Colombian obligation in the amount of $375,971 (2006 - $266,854) and an Argentine obligation in the amount of $423,515 (2006 - $327,752). Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties are as follows:

		December 31,
		2007			2006
Balance, beginning of year		$	594,606		$	67,732
Liability assumed with property acquisitions			—			476,168
Liability incurred			154,110			45,645
Foreign exchange			20,013			—
Accretion			30,757			5,061
Balance, end of year		$	799,486		$	594,606

 

8. Income Taxes

The income tax expense (recovery) reported differs from the amount computed by applying the statutory rate to loss before income taxes for the following reasons:

 

			2007			2006			2005
Loss before income taxes		$	(8,172,437	)	$	(5,146,324	)	$	(2,248,908	)
			32.12	%		34	%		34	%
Income tax benefit expected			(2,624,987	)		(1,749,750	)		(764,628	)
Benefit of tax losses not recognized			404,460			811,875			717,410
Impact of tax rate changes on future tax balances			277,508			-			-
Impact of foreign taxes			3,464,848			-			-
Enhanced tax depreciation incentive			(1,888,698	)		-			-
Stock-based compensation			204,918			260,495			17,990
Non-deductible items			1,909,588			-			-
Previously unrecognized tax assets			(1,452,870	)		-			-
Total Income Tax Expense		$	294,767		$	(677,380	)	$	(29,228	)

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

Future tax assets and liabilities consist of the following temporary differences:

 

			2007			2006
Future tax assets
Tax benefit of loss carryforwards		$	4,934,795		$	4,079,133
Book value in excess of tax basis			75,159			92,133
Foreign tax credits and other accruals			732,741			46,471
Capital losses			1,063,891			-
Future tax assets before valuation allowance			6,806,586			4,217,737
Valuation allowance			(4,748,150	)		(3,773,413	)
		$	2,058,436		$	444,324
Future tax asset - current		$	220,000			-
Future tax asset - long-term			1,838,436			444,324
		$	2,058,436		$	444,324
Future tax liabilities
Current - book value in excess of tax basis		$	1,107,802		$	7,153,112
Long-term - book value in excess of tax basis			9,234,926			7,153,112
Book value in excess of tax basis		$	10,342,728		$	7,153,112
Net future tax assets (liabilities)		$	8,284,292		$	7,153,112

 

The Company was required to calculate a deferred remittance tax in Colombia based on 7% of profits which are not reinvested in the business on the presumption that such profits would be transferred to the foreign owners up to December 31, 2006. As of January 1, 2007, the Colombian government rescinded this law, therefore, no further remittance tax liabilities will be accrued. The historical balance which was included on the Company’s financial statements as of December 31, 2007, as part of the deferred income taxes, was $1,332,016.

On January 1, 2007, the Company adopted the provisions of FIN 48 however there was no impact on the opening retained earnings of the Company as a result of this adoption. The Company has accrued no amounts as of December 31, 2007, for the potential payment of interest and penalties. For the year ended December 31, 2007, the Company has not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions. The Company or one of its subsidiaries files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and other foreign jurisdictions. The Company is subject to income tax examinations for the calendar tax years ending 2005 through 2007 in all jurisdictions.

As at December 31, 2007, the Company has future tax assets relating to net operating loss carryforwards of $15.83 million (2006 - $11.72 million) and capital losses of $3.04 million (2006 - nil) before valuation allowances. Of these losses, $9.35 million (2006 - $5.25 million) are losses generated by the foreign subsidiaries of the Company. Of the total losses, $3.97 million (2006 - $0.83 million) will begin to expire by 2012 and $11.85 million of net operating losses and $3.04 million of capital losses (2006 - $10.89 million) will begin to expire thereafter.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

9. Accrued Liabilities and Accounts Payable

The accounts payable and accrued liabilities are comprised of the following:

 

 

		Year Ended December 31, 2007												Year Ended December 31, 2006
		Corporate			Colombia			Argentina			Total			Corporate			Colombia			Argentina			Total
Capital		$	51,422		$	7,984,841		$	222,934		$	8,259,197		$	—		$	2,504,661		$	5,521,714		$	8,026,375
Payroll			476,089			512,756			211,860			1,200,705			664,957			333,679			313,589			1,312,225
Audit, legal, consultants			1,384,669			196,273			105,207			1,686,149			715,332			—			290,915			1,006,247
General and administrative			318,926			298,748			73,367			691,041			—			—			—			—
Operating			—			4,898,008			730,876			5,628,884			—			5,317,958			—			5,317,958
Total		$	2,231,106		$	13,890,626		$	1,344,244		$	17,465,976		$	1,380,289		$	8,156,298		$	6,126,218		$	15,662,805

 

10. Commitments and contingencies

Leases

 

Gran Tierra Energy holds three categories of operating leases: office, vehicle and housing. The Company pays monthly costs of $57,638 for office leases, $4,791 for vehicle leases, $9,400 for a compressor and $2,561 for certain employee accommodation leases in Colombia.

Future lease payments at December 31, 2007 are as follows:

Year		Cost
2008		$	833,799
2009			622,407
2010			562,374
2011			275,848
2012			280,121
Total lease payments		$	2,574,549

 

The Company entered into four capital leases in 2006 for office equipment in Calgary, Canada. The leases expire between 2008 and 2011. As of December 31, 2007 capital assets were valued at $21,841 (net of amortization of $17,870). Total rent expense for 2007 was $291,975 (2006 - $221,477; 2005 - $26,904).

 

71

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

Future lease payments under the office equipment leases at December 31, 2007 are as follows:

Year		Cost
2008		$	9,991
2009			4,849
2010			4,163
2011			1,053
2012			—
Total minimum lease payments			20,056
Less amount representing interest			1,664
Less amount included in current liabilities			8,879
		$	9,513

Capital lease agreements contain interest rates between 4.75 and 20.5 percent and mature over one to four years. Interest expense incurred under these capital leases to December 31, 2007 was $2,657 (2006 - $2,346).

The Company has contracted with a third party to provide catering services for its field operations in Colombia. The contract ends January 14, 2009. The remaining contractual commitment is $280,771 to be incurred evenly over the remaining duration of the contract.

The Company has contracted with a third party to provide a helicopter for field transportation for its Colombia field operations. The contract ends September 30, 2008. The minimum obligation under the contract is for 30 flight hours per month at a rate of $880 per hour. The remaining nine month obligation is $237,600.

Guarantees

 

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. Each indemnity, subject to certain exceptions, applies for as long as the indemnified person is a director or officer of one of the Company’s subsidiaries and/or affiliates. The maximum amount of any potential future payment cannot be reasonably estimated.

The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid. Management believes the resolution of these matters would not have a material adverse impact on the Company’s liquidity, consolidated financial position or results of operations.

Contingencies

 

As of December 31, 2007 the contracting parties of Guayuyaco Association Contract, Ecopetrol and Argosy, are working 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 Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production of up 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 the recovery of an amount equal to 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 outstanding pending agreement among the parties or determination through legal proceedings. The estimated value of the disputed extended test production is $2,361,188 with possible costs shared of 50% ($1,180,594) with the Company’s joint venture partner in the contract. No amount has been accrued in the financial statements related to this disagreement because the Company believes the probability of a negative outcome is low at this time.

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Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years ended December 31, 2007 and 2006 and

For the Period from Incorporation on January 26, 2005 to December 31, 2005

Expressed in US dollars, unless otherwise stated

 

11. Financial Instruments and Credit Risk

Financial Derivative Loss			Year Ended December 31, 2007
Realized financial derivative loss		$	391,345
Current portion of unrealized financial derivative Loss		$	1,593,629
Long-term portion of unrealized financial derivative loss			1,054,716
Total unrealized financial derivative loss		$	2,648,346
Financial derivative loss		$	3,039,690

Under the terms of the Credit Facility with Standard Bank Plc, the Company was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. In February 2007, the Company entered into a costless collar derivative instrument for crude oil based on WTI price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. The fair value of this derivative instrument was determined by management based on quotes obtained from the counterparty to the derivative instrument.

The Company’s financial instruments recognized in the balance sheet consist of cash, accounts receivable, taxes receivable, other long-term assets, accounts payable, current taxes payable, and accrued liabilities. The estimated fair values of the financial instruments have been determined based on the Company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair values of financial instruments approximate their book amounts due to the short-term maturity of these instruments. Most of the Company’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. The book value of the accounts receivable reflects management’s assessment of the associated credit risks.

12. Credit Facility

On February 28, 2007, the Company entered into a Credit Facility with Standard Bank Plc. The Facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of the Company’s petroleum reserves up to maximum of $50 million. The initial borrowing base is $7 million based on mid-year 2006 Independent Reserves Evaluation Report and the borrowing base will be re-determined semi-annually based on reserve evaluation reports. As a result of Standard Bank Plc’s review of our Mid-Year 2007 Independent Reserve Audit, the Company has received preliminary approval to increase our borrowing base to $20 million. The Facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the Facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base. The Facility is secured primarily on the Company’s Colombian assets. The Company was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the mid-year 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. Under the terms of the Facility, the Company is required to maintain compliance with specified financial and operating covenants. As at December 31, 2007, the Company has not drawn-down on this facility.

 

13. Restatement of Prior Period Financial Statements

 

The Company has restated its consolidated financial statements for the years ended December 31, 2007 and 2006 and unaudited quarterly financial information for each of the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007. In the course of preparing the Company’s interim financial statements for the quarterly report on Form 10-Q to be filed with the SEC for the quarter ended March 31, 2008, the Company discovered a misclassification of accounts payable and accrued liabilities in the 2007 interim financial statements for the previously reported quarters ended March 31, 2007, June 30, 2007 and September 30, 2007, and annual financial statements for the years ended December 31, 2006 and 2007 (collectively, the “Affected Financial Statements”). The misclassification resulted in a misstatement of cash flows from operating activities, with a corresponding offset to cash flows from investing activities. The restatements in the Affected Financial Statements had no effect on the Company’s previously reported net change in cash and cash equivalents and no impact on the Company’s previously reported consolidated balance sheets or consolidated statements of operations and accumulated deficit contained in the Affected Financial Statements.

 

The following table presents the impact of the error on previously reported amounts:

 

		Year Ended December 31, 2007
		As Previously Stated			Increase (Decrease)			As Restated
Net change in non-cash working capital
Accounts payable and accrued liabilities		$	261,658		$	2,546,762		$	2,808,420
Net cash provided (used in) operating activities		$	6,214,677		$	2,546,762		$	8,761,439
Oil and gas property expenditures		$	(13,429,570	)	$	(2,546,762	)	$	(15,976,332	)
Net cash used in investing activities		$	(12,845,943	)	$	(2,546,762	)	$	(15,392,705	)

		Year Ended December 31, 2006
		As Previously Stated			Increase (Decrease)			As Restated
Net change in non-cash working capital
Accounts payable and accrued liabilities		$	3,799,554		$	2,839,676		$	6,639,230
Net cash provided (used in) operating activities		$	(829,620	)	$	2,839,676		$	2,010,056
Oil and gas property expenditures		$	(7,434,463	)	$	(2,839,676	)	$	(10,274,139	)
Net cash used in investing activities		$	(45,366,912	)	$	(2,839,676	)	$	(48,206,588	)

 

73

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None.

 

 

 

The information required by Item 10 of Form 10-K with respect to Item 401 of Regulation S-K regarding our directors is incorporated herein by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our definitive Proxy Statement for the 2008 Annual Meeting of Stockholders (the “Proxy Statement”), a copy of which will be filed with the Securities and Exchange Commission on or before April 30, 2008.

 

The information required by Item 10 of Form 10-K with respect to Item 405 of Regulation S-K regarding section 16(a) beneficial ownership compliance is incorporated by reference from the information contained in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement.

 

For information with respect to our executive officers, see “Executive Officers of the Registrant” at the end of Part I of this report, following Item 4.

 

The information required by Item 10 of Form 10-K with respect to Items 407(c)(3), 407(d)(4) and 407(d)(5) is incorporated by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our Proxy Statement.

 

 

Gran Tierra Energy has adopted a Code of Business Conduct and Ethics (the “Code”) applicable to all of its Board members, employees and executive officers, including its Chief Executive Officer (Principal Executive Officer), and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer). Gran Tierra Energy has made the Code available on its website at http://www.grantierra.com/policies-practices/.

 

Gran Tierra Energy intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra Energy’s Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer by posting such information on its website at http://www.grantierra.com/policies-practices/. There were no amendments to the Code or waivers granted thereunder relating to the Principal Executive Officer, Principal Financial Officer or Principal Accounting Officer during fiscal 2007.

 

 

The information required by Item 11 of Form 10-K is incorporated herein by reference from the information contained in the sections entitles “Executive Compensation and Related Information,” “Director Compensation,” “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation” in our Proxy Statement.

 

 

The information required by Item 13 of Form 10-K is incorporated herein by reference from the information contained in the sections entitled “Certain Relationships and Related Transactions” and, with respect to director independence, the section entitled “Proposal 1 - Election of Directors,” in our Proxy Statement.

 

80

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The information required by Item 14 of Form 10-K is incorporated herein by reference from the information contained in the sections entitled “Principal Accountant Fees and Services” and “Audit Committee Pre-Approval Policies and Procedures’’ in our Proxy Statement.

 

 

 

(a) The following documents are filed as part of this Annual Report on Form 10-K:

 

(1) Financial Statements

 

The following documents are included as Part II, Item 8. of this Annual Report on Form 10-K:

 

		Page
Report of Independent Registered Chartered Accountants			52
Consolidated Statements of Operations and Accumulated Deficit			53
Consolidated Balance Sheets			54
Consolidated Statements of Cash Flow			55
Consolidated Statement of Shareholders’ Equity			56
Notes to the Consolidated Financial Statements			57
Supplementary Data (Unaudited)			74

 

(2) Financial Statement Schedules

 

None.

 

(3) Exhibits

 

See the Exhibit Index which follows the signature page of this Annual Report on Form 10-K, which is incorporated herein by reference.

 

81

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Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

			GRAN TIERRA ENERGY INC.
Date:	May 12, 2008		By:	/s/ Dana Coffield
				Dana Coffield
				Chief Executive Officer and President
				(Principal Executive Officer)
Date:	May 12, 2008		By:	/s/ Martin Eden
				Martin Eden
				Chief Financial Officer
				(Principal Financial and Accounting Officer)

82

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Name		Title		Date
/s/ Dana Coffield		Chief Executive Officer and President		May 12, 2008
Dana Coffield		(Principal Executive Officer)
/s/ Martin Eden		Chief Financial Officer		May 12, 2008
Martin Eden
*		Chairman of the Board, Director		May 12, 2008
Jeffrey Scott     *		Director		May 12, 2008
Verne Johnson
		Director		May 12, 2008
Nicholas Kirton
*		Director		May 12, 2008
Walter Dawson

* By:  /s/ Dana Coffield__________________

Dana Coffield

Attorney-in-Fact

 

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Exhibit
No.		Description		Reference
2.1		Acquisition Agreements		See Exhibits 10.1, 10.3, 10.5, 10.18, 10.46 and 10.47
3.1		Articles of Incorporation.		Incorporated by reference to Exhibit 3.1 to the Form SB-2, as amended, filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).
3.2		Certificate Amending Articles of Incorporation.		Incorporated by reference to Exhibit 3.2 to the Form SB-2, as amended, and filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).
3.3		Certificate Amending Articles of Incorporation.		Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
3.4		Certificate of Amendment to Articles of Incorporation.		Incorporated by reference to Exhibit 3.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 1, 2006 (File No. 333-111656).
3.5		Third Amended and Restated Bylaws of Gran Tierra Energy Inc.		Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on January 22, 2008 (File No. 333-111656).
4.1		Reference is made to Exhibits 3.1 to 3.5.
4.2		Form of Warrant issued in 2005.		Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
4.3		Form of Warrant issued to institutional and retail investors in connection with the private offering in June 2006.		Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.1		Share Purchase Agreement by and between Goldstrike Inc. and Gran Tierra Energy Inc. dated as of November 10, 2005.		Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).

 

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10.2		Form of Registration Rights Agreement by and among Goldstrike Inc. and the purchasers named therein.		Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
10.3		Assignment Agreement by and between Goldstrike Inc. and Gran Tierra Goldstrike Inc. dated as of November 10, 2005.		Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.4		Voting Exchange and Support Agreement by and between Goldstrike, Inc., 1203647 Alberta Inc., Gran Tierra Goldstrike Inc. and Olympia Trust Company dated as of November 10, 2005.		Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.5		Form of Split Off Agreement by and among Goldstrike Inc., Dr. Yenyou Zheng, Goldstrike Leasco Inc. and Gran Tierra Energy Inc.		Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).

 

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Exhibit
No.		Description		Reference
10.6		Employment Agreement between Gran Tierra Energy Inc. and Dana Coffield dated as of April 29, 2005, as amended. *		Incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.7		Employment Agreement between Gran Tierra Energy Inc. and James Hart dated as of April 29, 2005, as amended. *		Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.8		Employment Agreement between Gran Tierra Energy Inc. and Max Wei dated as of April 29, 2005, as amended. *		Incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.9		Employment Agreement between Gran Tierra Energy Inc. and Rafael Orunesu dated as of March 1, 2005, as amended. *		Incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.10		Form of Indemnity Agreement. *		Incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.12		2005 Equity Incentive Plan. *		Incorporated by reference to Exhibit 10.11 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.13		Form of Subscription Agreement.		Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
10.14		Details of the Goldstrike Special Voting Share.		Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).
10.15		Exchangeable Share Provisions.		Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).

 

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10.16		Refinery Contract between Refinor S.A.and Dong Wong Corporation - Golden Oil Corporation.		Incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).
10.17		Contract between Compañia General de Combustibles S.A. and Gran Tierra Energy Argentina S.A.		Incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656)
10.18		Securities Purchase Agreement, dated as of May 25, 2006, by and between Gran Tierra Energy, Inc and Crosby Capital, LLC.		Incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 1, 2006 (File No. 333-111656).
10.20		Form of Securities Purchase Agreement, dated as of June 20, 2006, by and among the Company and retail investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.		Incorporated by reference to Exhibit 10.20 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).

 

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Exhibit
No.		Description		Reference
10.21		Form of Subscription Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and retail investors subscribing for units of Gran Tierra Energy Inc. securities in a private offering.		Incorporated by reference to Exhibit 10.21 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.22		Securities Purchase Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and CD Investment Partners, Ltd.		Incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.23		Form of Registration Rights Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and institutional investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.		Incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.24		Form of Registration Rights Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and retail investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.		Incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.25		Registration Rights Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and CD Investment Partners, Ltd.		Incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.26		Lock-Up Agreement, dated June 20, 2006, by and among Sanders Morris Harris Inc. and the executive officers and directors of Gran Tierra Energy Inc.		Incorporated by reference to Exhibit 10.26 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.27		Registration Rights Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and Crosby Capital, LLC.		Incorporated by reference to Exhibit 10.27 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.28		Form of Securities Purchase Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.		Incorporated by reference to Exhibit 10.28 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).
10.29		Form of Subscription Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.		Incorporated by reference to Exhibit 10.29 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).

 

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10.30		Form of Registration Rights Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.		Incorporated by reference to Exhibit 10.30 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).
10.31		Form of Escrow Agreement.		Incorporated by reference to Exhibit 10.31 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.32		Form of Registration Rights Agreement by and among Goldstrike Inc. and the purchasers named therein.		Incorporated by reference to Exhibit 10.32 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.33		Form of Subscription Agreement by and among Goldstrike Inc., Gran Tierra Energy, Inc. and the investor identified therein.		Incorporated by reference to Exhibit 10.33 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.34		Form of Registration Rights Agreement by and among Gran Tierra Energy, Inc. f/k/a Goldstrike, Inc. and the purchasers named therein.		Incorporated by reference to Exhibit 10.34 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).

 

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Exhibit
No.		Description		Reference
10.35		Form of Subscription Agreement by and among Gran Tierra Energy, Inc. f/k/a Goldstrike, Inc. and the investor identified therein.		Incorporated by reference to Exhibit 10.35 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.36		Executive Employment Agreement dated December 1, 2006, by and between Gran Tierra Energy Inc. and Martin H. Eden. *		Incorporated by reference to Exhibit 10.36 to the current report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2007 (File No. 333-111656).
10.37		Credit Agreement dated February 22, 2007, by and among Gran Tierra Energy Inc, Gran Tierra Energy Colombia, Ltd., Argosy Energy Corp., and Standard Bank Plc.		Incorporated by reference to Exhibit 10.1 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.38		Note For Loans, dated February 22, 2007, by the Company in favor of Standard Bank Plc.		Incorporated by reference to Exhibit 10.2 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.39		GP Pledge Agreement, dated as of February 22, 2007, by the Company in favor of Standard Bank Plc.		Incorporated by reference to Exhibit 10.3 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.40		Partnership Pledge Agreement, dated as of February 22, 2007, by and among the Company and Argosy Energy Corp., in favor of Standard Bank Plc.		Incorporated by reference to Exhibit 10.4 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.41		Collection Account Pledge Agreement, dated as of February 22, 2007, by Gran Tierra Energy Colombia, Ltd. in favor of Standard Bank Plc.		Incorporated by reference to Exhibit 10.5 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.42		ISDA 2002 Master Agreement, dated as of February 22, 2007, by and among the Company and Standard Bank Plc, and the Schedule thereto.		Incorporated by reference to Exhibit 10.6 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.43		Blocked Account Control Agreement, dated as of February 22, 2007, by and among Gran Tierra Energy Colombia, Ltd., Standard Bank Plc and JPMorgan Chase Bank.		Incorporated by reference to Exhibit 10.7 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).

 

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10.44		Share Pledge Agreement, dated as of February 22, 2007, by and among the Company and Standard Bank Plc.		Incorporated by reference to Exhibit 10.8 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.45		First Priority Open Pledge Agreement Over Credit Rights Derived From A Crude Oil Commercial Sales Agreement, dated as of February 22, 2007, by and among Gran Tierra Energy Colombia, Ltd. and Standard Bank Plc.		Incorporated by reference to Exhibit 10.9 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.46		Contract between Ecopetrol S.A., and Argosy Energy International, for the sale of crude oil, dated December 1, 2006		Incorporated by reference to Exhibit 10.46 to the Annual Report on Form 10-KSB filed with the Securities and Exchange Commission on March 30, 2007 (File No. 333-111656).
10.47		Palmar Largo Assignment Agreement, dated September 1, 2005, between Don Won Corporation (Sucursal Argentina), and Gran Tierra Inc.		Incorporated by reference to Exhibit 10.47 to the Annual Report on Form 10-KSB filed with the Securities and Exchange Commission on March 30, 2007 (File No. 333-111656).
10.48		Escrow Agreement dated as of the ___th day of June, 2006, among Gran Tierra Energy, Inc. and McGuireWoods LLP, as Escrow Agent		Incorporated by reference to Exhibit 10.48 to the Form S-1/A filed with the Securities and Exchange Commission on May 4, 2007 (File No. 333-140171).
10.49		Employment Agreement, dated April 1, 2006, between Argosy Energy International and Edgar Dyes. *		Incorporated by reference to Exhibit 10.49 to the Form S-1/A filed with the Securities and Exchange Commission on May 4, 2007 (File No. 333-140171).
10.50		Form of Liquidated Damages Waiver		Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on August 14, 2007 (File No. 333-111656).

 

10.51		2007 Equity Incentive Plan.*		Incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on October 19, 2007 (File No. 333-146815).
10.52		Form of Option Agreement under the Company’s 2007 Equity Incentive Plan.*		Incorporated by reference to Exhibit 99.1 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).

 

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10.53		Form of Grant Notice under the Company’s 2007 Equity Incentive Plan.*		Incorporated by reference to Exhibit 99.2 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).
10.54		Form of Exercise Notice under the Company’s 2007 Equity Incentive Plan.*		Incorporated by reference to Exhibit 99.3 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).

 

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Exhibit
No.		Description		Reference
21.1		List of subsidiaries.		Previously filed
23.1		Consent of Deloitte & Touche LLP		Filed herewith.
23.2		Consent of Gaffney, Cline and Associates		Filed herewith.
24.1		Power of Attorney.		Previously filed
31.1		Certification of Principal Executive Officer		Filed herewith.
31.2		Certification of Principal Financial Officer		Filed herewith.
32.1		Certification of Principal Executive and Financial Officers		Filed herewith.

 

* Management contract or compensatory plan or arrangement.

 

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