10-K 1 v210811_10k.htm Unassociated Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 

 
FORM 10-K
 
(Mark One)
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the year ended December 31, 2010
 
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____________ to _____________
 
Commission File Number 001-34018
 

 
GRAN TIERRA ENERGY INC.
(Exact name of registrant as specified in its charter)
 
Nevada
 
98-0479924
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
300, 625 11th Avenue SW
Calgary, Alberta, Canada T2R 0E1
(Address of principal executive offices, including zip code)
 
(403) 265-3221
(Registrant’s telephone number, including area code)  
 

 
Securities Registered Pursuant to Section 12(b) of the Act:
 
Title of Each Class
Name of Each Exchange on Which Registered
 
Common Stock, par value $0.001 per share
  NYSE Amex 
 
 
Toronto Stock Exchange
 
 
Securities Registered Pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x    No ¨
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨      No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x       No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes x      No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer   x     Accelerated filer ¨
 
Non-accelerated filer ¨ (do not check if a smaller reporting company)  Smaller reporting company ¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨    No x
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $1,197,806,292 (including shares issuable upon exercise of exchangeable shares). Aggregate market value excludes an aggregate of 1,101,633 shares of common stock and 11,125,525 shares issuable upon exercise of exchangeable shares held by officers and directors and by each person known by the registrant to own 10% or more of the outstanding common stock on such date. Exclusion of shares held by any of these persons should not be construed to indicate that such person possesses the power, direct or indirect, to direct or cause the direction of the management or policies of the registrant, or that such person is controlled by or under common control with the registrant.
 
On February 18, 2011, the following numbers of shares of the registrant’s capital stock were outstanding: 240,857,632 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value,  representing 7,811,112 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and  one share of Special B Voting Stock, $0.001 par value,  representing 9,539,042 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
The information required by Part III of this report, to the extent not set forth herein, is incorporated by reference from the Registrant’s definitive proxy statement relating to the 2011 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the fiscal year to which this Report relates.

 
 

 
 
GRAN TIERRA ENERGY INC.
 
ANNUAL REPORT ON FORM 10-K
 
Year ended December 31, 2010
 
TABLE OF CONTENTS
 
        
Page
No.
PART I
       
Item 1.
 
Business
 
3
Item 1A.
 
Risk Factors
 
16
Item 1B.
 
Unresolved Staff Comments
 
26
Item 2.
 
Properties
 
26
Item 3.
 
Legal Proceedings
 
39
Item 4.    Removed and reserved    39
         
PART II
       
Item 5.
 
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
41
Item 6.
 
Selected Financial Data
 
43
Item 7.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
44
Item 7A.
 
Quantitative and Qualitative Disclosures About Market Risk
 
69
Item 8.
 
Financial Statements and Supplementary Data
 
70
Item 9.
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
102
Item 9A.
 
Controls and Procedures
 
102
Item 9B
 
Other Information
    104
 
 
 
 
 
PART III
       
Item 10.
 
Directors, Executive Officers and Corporate Governance
 
104
Item 11.
 
Executive Compensation
 
104
Item 12.
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
104
Item 13.
 
Certain Relationships and Related Transactions, and Director Independence
 
105
Item 14.
 
Principal Accounting Fees and Services
 
105
PART IV
       
Item 15.
 
Exhibits, Financial Statement Schedules
 
105
SIGNATURES
 
106

 
Page 2 of 113

 
 
PART I
 
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). All statements other than statements of historical facts included in this Annual Report on Form 10-K including without limitation statements in the Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct and because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, those set out in Part I, Item 1A “Risk Factors” in this Annual Report on Form 10-K. The information included herein is given as of the filing date of this Form 10-K with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Annual Report on Form 10-K to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.
 
Item 1. Business
 
General
 
Gran Tierra Energy Inc. together with its subsidiaries (“Gran Tierra” or “we”) is an independent international energy company engaged in oil and gas acquisition, exploration, development and production. We own oil and gas properties in Colombia, Argentina, Peru and Brazil. A detailed description of our properties can be found under Item 2 “Properties”. All dollar ($) amounts referred to in this Form 10-K are United States (U.S.) dollars, unless otherwise indicated.
 
In 2010, our geographic focus was on South America. We focused on development of producing fields and generation of exploration prospects in Colombia, including the award of three blocks in the 2010 Colombia Bid Round, and acquisition of a working interest in an additional block. In Argentina, we maintained existing production and commenced work on a natural gas project which was suspended in February, 2011 and will be abandoned.  We continue to review alternatives to evaluate to field development. In Peru, we received Environmental Impact Assessment approvals, commenced seismic and preparation for drilling operations and further expanded our exploration portfolio through acquisition of working interests in four additional blocks. In Brazil, we entered into our initial exploration and development transaction by acquiring a 70% working interest in each of in four blocks in the on-shore Reconcavo Basin. The blocks awarded in Colombia and acquired in Peru and Brazil are still subject to various approvals. On January 17, 2011, we entered into an agreement to acquire all the issued and outstanding shares and warrants of Petrolifera Petroleum Ltd. (“Petrolifera”) pursuant to a Plan of Arrangement (the “Arrangement”), subject to Petrolifera shareholder, regulatory, stock exchange, and court approvals.  Petrolifera is a Canadian based international oil and gas company listed on the Toronto Stock Exchange and owns working interests in 11 exploration and production blocks - three located in Colombia, three in Peru and five in Argentina.  The Arrangement is expected to close in March 2011.  See “Subsequent Events” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further details.
 
Our principal executive offices are located at 300, 625-11th Avenue S.W., Calgary, Alberta, Canada. The telephone number at our principal executive office is (403) 265-3221. Our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 which we make available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC, are available free of charge to the public on our website www.grantierra.com. To access our SEC filings, select SEC Filings from the investor relations menu on our website, which will provide a list of our SEC filings. Our website address is provided solely for informational purposes. We do not intend, by this reference, that our website should be deemed to be part of this Annual Report. Any materials we have filed with the SEC may be read and/or copied at the SEC’s Public Reference Room at 100 F Street N.E. Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding us. The SEC’s website address is www.SEC.gov.

The Oil and Gas Business
 
In the discussion that follows, and in Item 2 “Properties”, we discuss our interests in wells and/or acres in gross and net terms. Gross oil and natural gas wells or acres refer to the total number of wells or acres in which we own a working interest. Net oil and natural gas wells or acres are determined by multiplying gross wells or acres by the working interest that we own in such wells or acres. Working interest refers to the interest we own in a property, which entitles us to receive a specified percentage of the proceeds of the sale of oil and natural gas, and also requires us to bear a specified percentage of the cost to explore for, develop and produce that oil and natural gas. A working interest owner that owns a portion of the working interest may participate either as operator or by voting its percentage interest to approve or disapprove the appointment of an operator, and drilling and other major activities in connection with the development of a property.

 
Page 3 of 113

 

We also refer to royalties and farm-in or farm-out transactions. Royalties are paid to governments on the production of oil and gas, either in kind or in cash. Royalties also include overriding royalties paid to third parties. Our reserves, production and sales are reported net after deduction of royalties. Farm-in or farm-out transactions refer to transactions in which a portion of a working interest is sold by an owner of an oil and gas property. The transaction is labeled a farm-in by the purchaser of the working interest and a farm-out by the seller of the working interest. Payment in a farm-in or farm-out transaction can be in cash or in kind by committing to perform and/or pay for certain work obligations.

Several items that relate to oil and gas operations, including aeromagnetic and aerogravity surveys, seismic operations and several kinds of drilling and other well operations, are also discussed in this document.

In the petroleum industry, geologic settings with proven petroleum source rocks, migration pathways, reservoir rocks and traps are referred to as petroleum systems.

Aeromagnetic and aerogravity surveys are a remote sensing process by which data is gathered about the subsurface of the earth. An airplane is equipped with extremely sensitive instruments that measure changes in the earth's gravitational and magnetic field. Variations as small as 1/1,000th in the gravitational and magnetic field strength and direction can indicate structural changes below the ground surface. These structural changes may influence the trapping of hydrocarbons. These surveys are an inexpensive way of gathering data over large regions.

Seismic data is used by oil and natural gas companies as their principal source of information to locate oil and natural gas deposits, both for exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations. 2-D Seismic is the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. 3-D seismic data is collected using a grid of energy sources, which are generally spread over several square miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

Wells drilled are classified as exploration, development or stratigraphic. An exploration well is a well drilled in search of a previously undiscovered hydrocarbon-bearing reservoir. A development well is a well drilled to develop a hydrocarbon-bearing reservoir that is already discovered. Exploration and development wells are tested during and after the drilling process to determine if they have oil or natural gas that can be produced economically in commercial quantities. If they do, the well will be completed for production, which could involve any range of a wide variety of equipment, the specifics of which depend on a number of technical geological and engineering considerations. If there is no oil or natural gas (a “dry” well), or there is oil and natural gas but the quantities are too small and/or too difficult to produce, the well will be abandoned. Abandonment is a completion operation that involves closing or “plugging” the well and remediating the drilling site. An injector well is a development well that will be used to inject fluid into a reservoir to increase production from other wells.  A stratigraphic well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

Workover is a term used to describe remedial operations on a previously completed well to clean, repair and/or maintain the well for the purposes of increasing or restoring production. It could include well deepening, plugging portions of the well, working with cementing, scale removal, acidizing, fracture stimulation, changing tubulars or installing/changing equipment to provide artificial lift.

BOPD is a commonly used abbreviation in the oil and gas business which means barrels of oil per day.

In our discussion below, we refer to various oil fields and blocks. A more detailed discussion of these areas is set forth in Item 2 of this Form 10-K.

 
Page 4 of 113

 

Development of Our Business
 
We made our initial acquisition of oil and gas producing and non-producing properties in Argentina in September 2005. During 2006, we acquired oil and gas producing and non-producing assets in Colombia, non-producing assets in Peru and additional properties in Argentina. During 2008, we increased our holdings in Colombia through the acquisition of Solana Resources Limited (“Solana”). In 2009 we added exploration blocks in Colombia by converting our two Technical Evaluation Areas to three exploration and exploitation blocks. In 2010, we added three blocks in Colombia through the Colombia Bid Round 10 and acquired a 55% interest in one block through a farm-in, acquired a 20% working interest in three additional blocks in Peru, acquired a 60% working interest in Block 95 in Peru and acquired a 70% working interest in four on-shore blocks in Brazil.  The blocks awarded in Colombia and acquired in Peru and Brazil are still subject to various governmental approvals.  As a result of these acquisitions, including the acquisitions subject to various government approvals, our acreage as of December 31, 2010 includes:

 
2,637,916 gross acres in Colombia (2,289,169 net) covering sixteen exploration and production contracts, five of which are producing and all but one of which are operated by Gran Tierra (includes 1,470,645 gross and net acres subject to government approval);

 
1,628,473 gross acres (1,294,107 net) in Argentina covering seven exploration and production contracts, four of which are producing, and all but one of which are operated by Gran Tierra;

 
11,431,141 gross acres (5,544,820 net) in Peru covering six exploration and exploitation licenses, all of which are frontier exploration areas and three of which are operated by Gran Tierra (includes 7,995,101 gross acres and 2,108,780 net acres subject to government approval); and

 
27,075 gross acres (18,953 net) in Brazil covering four exploration blocks to be operated by Gran Tierra (all acreage subject to government approval).

 
Page 5 of 113

 

Colombia
 

In Colombia in 2010, on the Chaza Block, we continued the development of our Costayaco field, completing Costayaco-11 in June 2010 as a producing well and commenced drilling of Costayaco-12 and Costayaco-13 in December 2010.

In early January 2010, we plugged and abandoned an exploration well, Dantayaco-1.  We also drilled an exploration well on the Chaza Block in May (Moqueta-1), which resulted in an oil discovery.  The Moqueta-2 delineation well was spud in July, the Moqueta-3 delineation well was spud in September and an additional delineation well, Moqueta-4, was spud in late December with testing expected to be complete in March 2011.  The design, permitting and construction of a pipeline to connect Moqueta to existing infrastructure is continuing and first production from Moqueta is expected early in the second quarter of 2011.  A third exploration well in the Chaza Block was spud in November (Pacayaco-1) and was suspended until the acquisition of new 3D seismic was completed and interpreted.  The acquisition and interpretation is now complete and we plan to drill either a new well or a sidetrack of the existing well late in the second quarter of 2011. On our Rio Magdalena Block, we drilled the Popa-3 well, which has been suspended pending evaluation. In our non-operated Garibay Block, we drilled one exploration well (Jilguero-1), which resulted in an oil discovery.   On our Piedemonte Sur Block, preparations for an exploration well, Taruka-1, began in December 2010.  The well was spud in January 2011 and was plugged and abandoned in February 2011.

 
Page 6 of 113

 

We were awarded 3 blocks in the Colombia Bid Round 10, Cauca-6, Cauca-7, and Putumayo-10, in June 2010.  These are pending Agencia Nacional de Hidrocarburos or National Hydrocarbons Agency (“ANH”) approval and represent 1,470,646 gross acres (1,470,646 net acres). We also acquired a 55% interest in the Putumayo -1 Block through a farm-in.

Details of our 2011 plans are contained in Item 2 “Properties”.

Argentina


In Argentina in July 2010, we began re-entry and sidetrack operations on the Valle Morado GTE.St.VMor-2001 gas well.  In February 2011, these operations were suspended and the wellbore will be abandoned due to a number of operational challenges encountered.  We continue to review alternatives associated with the field development.  Also in 2010, several successful workovers were completed on wells in other blocks in order to maintain production levels.  Gran Tierra filed an application for relinquishment related to the Ipaguazu Block in 2010 and is awaiting government approval.

Details of our 2011 plans are contained in Item 2 “Properties”.

 
Page 7 of 113

 

Peru


In Peru in 2010, we received Environment Impact Assessment (“EIA”) approvals for seismic and drilling operations on Block 122 and Block 128.  We completed our seismic acquisition program in Block 128 and partially completed the seismic program in Block 122.  Completion of the remaining seismic program in Block 122 is expected in the first quarter of 2011 and an exploration well is planned for the third quarter of 2011.  Pad construction for the first exploration well in Block 128 began in December and the well was spud in February 2011.  Also in February 2011, we relinquished 20% of Block 128.

 
Page 8 of 113

 

In September 2010, we entered into an agreement to acquire a 20% working interest in Block 123, Block 124, and Block 129, subject to government approval.  Burlington Resources Peru Ltd. (a wholly owned subsidiary of ConocoPhillips) is the operator of these three blocks.  A 747 kilometer 2D seismic program was shot in these three blocks in 2010.

In December 2010, we entered into an agreement to acquire operatorship and a 60% working interest in Block 95, subject to government approval.

Details of our 2011 plans are contained in Item 2 “Properties”.

Brazil


In August 2010, we entered into an agreement to acquire operatorship and a 70% working interest in four onshore blocks in the Reconcavo Basin (Blocks 129, 142, 155 and 224), subject to government approval .  In 2010, a 93 kilometer 2D seismic program was completed on three of these blocks.

Details of our 2011 plans are contained in Item 2 “Properties”.

 
Page 9 of 113

 

Business Strategy

Our plan is to continue to build an international oil and gas company through acquisition and exploitation of under-developed prospective oil and gas assets, and to develop these assets with exploration and development drilling to grow commercial reserves and production. Our initial focus is in select countries in South America, currently Colombia, Argentina, Peru, and Brazil; we will consider other regions for future growth should those regions make strategic and commercial sense in creating additional value.
 
We have applied a two-stage approach to growth, initially establishing a base of production, development and exploration assets by selective acquisitions, and secondly achieving additional reserve and production growth through drilling. We intend to duplicate this business model in other areas as opportunities arise. We pursue opportunities in countries with proven petroleum systems; attractive royalty, taxation and other fiscal terms; and stable legal systems.

A key to our business plan is positioning — being in the right place at the right time with the right resources. The fundamentals of this strategy are described in more detail below:

 
Position in countries that are welcoming to foreign investment, that provide attractive fiscal terms, that have stable legal systems, that offer opportunities that we believe have been previously ignored or undervalued, and that have an active market with many available deals;

 
Build a balanced portfolio of production, development and exploration assets and opportunities, with a drilling inventory that balances risks and rewards to create value;

 
Retain operatorship of assets whenever possible to retain control of work programs, budgets, prospect generation, drilling operations and development activities;

 
Engage qualified, experienced and motivated professionals;

 
Establish an effective local presence, with strong constructive relationships with host governments, ministries, agencies and communities in which we operate;

 
Consolidate land and properties in close proximity to build operating efficiency; and

 
Manage asset and drilling portfolios closely, assessing value to the company and making changes where needed.

Research and Development
 
We have not expended any resources on pursuing research and development initiatives. We use existing technology and processes for executing our business plan.
 
Markets and Customers
 
Ecopetrol S.A. (“Ecopetrol”), the Colombian majority state owned oil company, is the purchaser of most of the crude owned by our Colombian branches, Gran Tierra Energy Colombia Ltd. (“Gran Tierra Colombia”) and Solana Petroleum Exploration (Colombia) Ltd. (“Solana Colombia”). We deliver our oil to Ecopetrol through our transportation facilities which include pipelines, gathering systems and trucking. The majority of the oil produced is transported by pipeline. Varying amounts of oil are trucked: (i) from Santana Station to Ecopetrol’s storage terminal at Orito, a distance of approximately 46 kilometers, and (ii) from Costayaco to Ecopetrol’s storage terminal at Neiva (Dina Station), approximately 350 kilometers north of the Chaza Block. Crude oil prices for sales to Ecopetrol are defined by multi-year agreements with Ecopetrol based on West Texas Intermediate NYMEX (“WTI/NYMEX”) price less adjustments for quality and transportation. These agreements are subject to renegotiation periodically and generally contain mutual termination provisions with 90 days notice. For commercial purposes, on November 8, 2010, we agreed to amend our Chaza Block Crude Oil Sales Agreement between Gran Tierra Colombia and Ecopetrol whereby Ecopetrol was required to purchase 90% (previously 100%) of the volume of crude oil production produced by Gran Tierra Colombia in the Chaza Block (exclusive of the volume of oil owned by ANH corresponding to royalties).  Subsequently, on December 30, 2010, this agreement was further amended to require Gran Tierra Colombia to sell 100% of its Chaza Block crude oil to Ecopetrol (exclusive of the volume of oil owned by ANH corresponding to royalties).  Additionally, on December 30, 2010, both agreements (Gran Tierra Colombia and Solana Colombia with Ecopetrol), previously expiring December 31, 2010 were extended to June 30, 2011, but with a clause that allows both companies to sell to third parties any crude oil not accepted by Ecopetrol.

 
Page 10 of 113

 

In October 2010, Gran Tierra Colombia entered into a one year contract to sell up to 2,000 barrels of oil per day of Chaza Block crude oil production to Petrobras International Braspetro B.V. (“Petrobras International”). Sales of Chaza Block crude oil production to Petrobras International commenced in December 2010 with volumes trucked to their Rio Ceibas Station (near  Neiva). Crude oil prices for sales to Petrobras International are based on WTI price less adjustments for quality, transportation, marketing and handling. This contract may be extended an additional year if agreed to by both parties and contains mutual termination provisions with 90 days notice. In December 2010, a similar contract was executed between Solana Colombia and Petrobras International.

Our oil in Colombia is good quality light oil. In 2010, we received 100% of our revenue in U.S. dollars. Sales to Ecopetrol accounted for 96% of Gran Tierra’s revenues in 2010, 94% of our revenues in 2009 and 89% of our revenues in 2008.

Gas produced on the Magangue Block in the Lower Magdalena Basin, (Guepaje – 1 Well) is sold to Surtigas. The gas price is determined by contract with the customer. Sales to Surtigas accounted for less than 1% of our revenues in 2010, 2009 and 2008.

We market our own share of production in Argentina. The purchaser of our oil in Argentina is Refineria del Norte S.A. (“Refinor S.A.”) . In Argentina, export prices for crude oil are subject to an export withholding tax based on WTI price. This export tax has the effect of limiting the actual realized price for domestic sales. Our crude oil prices are agreed on a spot basis with Refinor S.A., based on WTI price less adjustments for quality, transportation and an adjustment equivalent to the export tax. We receive revenues in Argentine pesos, based on U.S. dollar prices at the exchange rate on the payment date. Our contract with Refinor S.A. expired January 1, 2008; however, we are continuing sales of our oil under monthly agreements with Refinor S.A. Sales to Refinor S.A. accounted for 4% of our revenues in 2010, 5.8% of our revenues in 2009 and 9% of our revenues in 2008.

Gran Tierra entered Brazil in 2010 by acquiring a 70% working interest in four exploration blocks in the Reconcavo Basin.  One of these blocks, Block REC-155 has current production of approximately 500 barrels of oil per day gross. Gran Tierra will be the operator of these blocks once government approval for the acquisition of this working interest is obtained.  Petróleo Brasileiro S.A (“Petrobras”) is the purchaser of most of the crude oil produced from this block. Crude oil is trucked 26 miles to the Petrobras Carmo Oil Treatment Station. Crude oil prices for sales to Petrobras are at spot market prices, based on Brent DTD (“Brent”), until the producing well completes long term testing. At that time a crude oil sales contract can be entered into by both parties.

There were no sales in any other country other than Colombia and Argentina in 2010, 2009 and 2008.
 
See “Our Oil Sales Will Depend on a Relatively Small Group of Customers, Which Could Adversely Affect Our Financial Results ” and “Negative Political and Regulatory Developments in Argentina May Negatively Affect our Operations ” in Item 1A “Risk Factors” for a description of the risks faced by our dependency on a small number of customers and the regulatory systems under which we operate.
 
Competition
 
The oil and gas industry is highly competitive. We face competition from both local and international companies in acquiring properties, contracting for drilling and other oil field equipment and securing trained personnel. Many of these competitors have financial and technical resources that exceed ours, and we believe that these companies have a competitive advantage in these areas. Others are smaller, and we believe our technical and financial capabilities give us a competitive advantage over these companies.

See “Competition in Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair Our Business” in Item 1A “Risk Factors” for risks associated with competition.

Geographic Information
 
Information regarding our geographic segments, including information on revenues, assets, expenses, and income can be found in Note 4 to the Financial Statements, Segment and Geographic Reporting, in Item 8 “Financial Statements and Supplementary Data”, which information is incorporated by reference here. Long lived assets are Property, Plant and Equipment, which includes all oil and gas assets, furniture and fixtures, automobiles and computer equipment. No long lived assets are held in our country of domicile, which is the United States of America. Corporate assets include assets held by our corporate head office in Calgary, Alberta, Canada, and assets held in Peru and Brazil. Because all of our exploration and development operations are in South America, we face many risks attendant with these operations.  See Item 1A “Risk Factors” for risks associated with our foreign operations.

Regulation
 
The oil and gas industry in Colombia, Argentina, Peru and Brazil is heavily regulated. Rights and obligations with regard to exploration, development and production activities are explicit for each project; economics are governed by a royalty/tax regime. Various government approvals are required for property acquisitions and transfers, including, but not limited to, meeting financial and technical qualification criteria in order to be certified as an oil and gas company in the country. Oil and gas concessions are typically granted for fixed terms with opportunity for extension.

 
Page 11 of 113

 

Colombia
 
In Colombia, prior to 2004, Ecopetrol was the administrator of all hydrocarbons and therefore executed contracts with oil companies under different contractual types such as Association Contracts and Shared Risk Contracts. Under Association Contracts, the oil companies (“Associate”) assumed all risk during the exploration phase and Ecopetrol had the obligation to reimburse to the Associate, after the commerciality was accepted by Ecopetrol, all the direct exploration costs which the Associate incurred.  If Ecopetrol did not accept the initial commerciality of a field, the Associate may continue the activities at its sole risk and Ecopetrol would retain the right to back-in later, after Ecopetrol reimbursed the Associate for the initial exploitation work and exploration costs plus certain penalties, depending upon at what stage Ecopetrol later declared commerciality of the field.

Effective June 2004, the regulatory regime in Colombia underwent a significant change with the formation of the ANH. The ANH is now the administrator of the hydrocarbons in the country and therefore is responsible for regulating the Colombian oil industry, including managing all exploration lands. Ecopetrol became a public company owned in majority by the state with the main purpose of exploring and producing hydrocarbons similar to any other oil company. However, Ecopetrol continues to have rights under the existing contracts executed with oil companies before ANH was created. Ecopetrol continues to be the major purchaser and marketer of crude oil in Colombia, and also operates the majority of the oil transportation infrastructure in the country.

In conjunction with this change, the ANH developed a new exploration risk contract that took effect near the end of the first quarter of 2005. This Exploration and Production Contract has significantly changed the way the industry views Colombia. In place of the earlier association contracts in which the contractor assumed all the exploration risk and Ecopetrol had the right to back-in afterwards, the new agreement provides full risk/reward benefits for the contractor. Under the terms of the contract the successful operator retains the rights to all reserves, production and income from any new exploration block, subject to existing royalty and tax regulations. Each contract contains an exploration phase and a production phase. The exploration phase will contain a number of exploration periods and each period will have an associated work commitment. The production phase will last a number of years (usually 24) from the declaration of a commercial hydrocarbon discovery.

Gran Tierra operates in Colombia through two branches – Gran Tierra Colombia and Solana Colombia. Both are qualified as operators of oil and gas properties by ANH.

When operating under a contract, the contractor is the owner of the hydrocarbons extracted from the contract area during the performance of operations, and pays royalties which are collected by ANH or Ecopetrol, depending on the type of contract. The contractor can market the hydrocarbons in any manner whatsoever, subject to a limitation in the case of natural emergencies where the law specifies the manner of sale.
  
Argentina

The Hydrocarbons Law 17.319, enacted in June 1967, established the basic legal framework for the current regulation of exploration and production of hydrocarbons in Argentina. The Hydrocarbons Law empowers the National Executive Branch to establish a national policy for development of Argentina’s hydrocarbon reserves, with the main purpose of satisfying domestic demand. However, on January 5, 2007, Law 26.197 was passed by the Government of Argentina. This new legal framework replaces article one of the Hydrocarbons Law 17.319 and provides for the provinces to assume complete ownership, authority and administration of the crude oil and natural gas reserves located within their territories, including offshore areas up to 12 marine miles from the coast line. This includes all exploration, exploitation and transportation concessions.
 
On June 3, 2002, the Argentine government issued a resolution authorizing the Energy Secretariat to limit the amount of crude oil that companies can export. The restriction was to be in place from June 2002 to September 2002. However, on June 14, 2002, the government agreed to abandon the limit on crude oil export volumes in exchange for a guarantee from oil companies that domestic demand will be supplied. Oil companies also agreed not to raise natural gas and related prices to residential customers during the winter months and to maintain gasoline, natural gas and oil prices in line with those in other South American countries.
 
Near the end of 2007, the Argentine government issued decrees changing the withholding export tax structure and further regulating oil exports.
 
At the end of 2008, the Argentine government launched the Gas Plus and Petroleum Plus programs, new programs designed to stimulate investments in and production of natural gas and oil through providing incentives for new production of natural gas or oil, either from new discoveries, enhanced recovery techniques or reactivation of older fields. Companies must apply for the incentives, and qualification is based on a complex set of formulas involving increased production over a calculated base and increases in proved reserves for the year. Gran Tierra received credit under the Petroleum Plus program related to our production for the fourth quarter of 2008. Gran Tierra did not qualify for credit for oil production in 2009. In April 2010, the Federal Secretariat of Energy approved Gran Tierra’s Gas Plus project for the development of the Valle Morado field.

 
Page 12 of 113

 

In October 2010, the Argentine Gas Authority (“ENARGAS”) issued Regulation I-1410 aiming at securing the supply of natural gas to residential consumers and small industry given the decline in gas production and the expected growing demand for gas.  The regulation includes all the procedures created by the authorities since 2004 (restrictions of exports, deviation of gas sales to residential consumption) and gives ENARGAS power to control gas marketing in order to assure the supply of gas to residential consumers and small industry. This regulation is being challenged by gas producers on the grounds that it illegally interferes in their gas marketing activities.

See “Negative Political and Regulatory Developments in Argentina May Negatively Affect our Operations” in Item 1A “Risk Factors” for a description of the risks associated with Argentine government controls.

Peru
 
Peru’s hydrocarbon legislation, which includes the Organic Hydrocarbon Law No. 26221enacted in 1993 and the regulations thereunder (the “Organic Hydrocarbon Law”), governs our operations in Peru. This legislation covers the entire range of petroleum operations, defines the roles of Peruvian government agencies which regulate and interact with the oil and gas industry, requires that investments in the petroleum sector be undertaken solely by private investors (either national or foreign), and provides for the promotion of the development of hydrocarbon activities based on free competition and free access to all economic activities. This law provides that pipeline transportation and natural gas distribution must be handled via contracts with the appropriate governmental authorities. All other petroleum activities are to be freely operated and are subject only to local and international safety and environment standards.

Under this legal system, Peru is the owner of the hydrocarbons located below the surface in its national territory. However, Peru has given the ownership right to extracted hydrocarbons to Perupetro S.A. (Perupetro), a state company responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation activities in Peru. Perupetro is empowered to enter into contracts for either the exploration and exploitation or just the exploitation of petroleum and natural gas on behalf of Peru, the nature of which are described further below. The Peruvian government also plays an active role in petroleum operations through the involvement of the Ministry of Energy and Mines, the specialized government department in charge of establishing energy, mining and environmental protection policies, enacting the rules applicable to all these sectors and supervising compliance with such policies and rules. We are subject to the laws and regulations of all of these entities and agencies.

Perupetro generally enters into either license contracts or service contracts for hydrocarbon exploration and exploitation. Peru’s laws also allow for other contract models, but the investor must propose contract terms compatible with Peru’s interests. We only operate under license contracts and do not foresee operating under any services contracts. A company must be qualified by Perupetro to enter into hydrocarbon exploration and exploitation contracts in Peru. In order to qualify, the company must meet the standards under the Regulations Governing the Qualifications of Oil Companies. These qualifications generally require the company to have the technical, legal, economic and financial capacity to comply with all obligations it will assume under the contract based on the characteristics of the area requested, the possible investments and the environmental protection rules governing the performance of its operations. When a contractor is a foreign investor, it is expected to incorporate a subsidiary company or registered branch in accordance with Peru’s corporate law and appoint representatives in accordance with the Organic Hydrocarbon Law who will interact with Perupetro.

Gran Tierra has been qualified by Perupetro with respect to our current contracts for Block 122 and Block 128 and is awaiting approval from the Government of Peru for the recently acquired interests in Block 123, Block 124, Block 129 and Block 95. However, Perupetro reviews the qualification for each specific contract to be signed by a company. Additionally, the qualification for foreign companies is granted in favor of the home office or corporation, which is jointly and severally liable at all times for the technical, legal, economic and financial capacity of its Peruvian subsidiary or branch.

When operating under a license contract, the licensee is the owner of the hydrocarbons extracted from the contract area during the performance of operations, and pays royalties which are collected by Perupetro. The licensee can market or export the hydrocarbons in any manner whatsoever, subject to a limitation in the case of natural emergencies where the law stipulates such manner.
  
Brazil

In Brazil, law No. 2004 enacted in 1953 instituted the state monopoly of the petroleum industry and created Petrobras, a corporation using public and private funds under control of the Federal Union of Brazil (“Federal Union”), to be the exclusive operator of exploration and production concessions in Brazil.

Amendment No. 9 to the Federal Constitution, issued on November 9, 1995, authorized the Federal Union to execute contracts with state and private companies for the exploration and production of oil and natural gas, as well as for the refining, transportation, import and export of oil, natural gas and its by-products, discontinuing Petrobras’ exclusive right to operate exploration and production concessions in Brazil.

 
Page 13 of 113

 

Oil and natural gas located in Brazil, whether onshore or offshore, are the property of the Federal Union. Under the principles of the Federal Constitution the national territory comprises all land and the continental shelf. Brazil is a signatory of the conventions regulating the economic use of the sea and its subsoil. Brazil is thus entitled to the enjoyment of the resources over the territorial sea and marine platform up to the limits indicated in the pertinent treaties. Part of the revenues from the exploitation of the hydrocarbon resources collected by the Federal Union is passed on to States and Municipalities.

The new institutional and regulatory model is governed by Law No. 9478, the Petroleum Law, which controls the granting of concessions and authorization for carrying out exploration and production activities to Brazilian companies, i.e., those created in accordance with Brazilian laws, with head offices and management located within the national territory.

In accordance with the Petroleum Law, the acquisition of oil and natural gas property and oil and gas operations by state and private companies are subject to legal, technical and economic standards and regulations issued by the National Petroleum Agency (“ANP”), the agency created by the Petroleum Law and vested with regulatory and inspection authority to ensure adequate operational procedures with respect to industry activities and the supply of fuels throughout the national territory.

ANP has authority for the implementation of the national oil and natural gas policy. ANP conducts bid rounds to award exploration, development and production contracts, as well as to approve the construction and operation of refineries and gas processing units, transportation facilities (including port terminals), import and export of oil and natural gas, as well as supervision of the activities which integrate the petroleum industry and the general enforcement of the Petroleum Law.

The granting of concession contracts is preceded by a public bid procedure, regulated by ANP. Any company evidencing technical, financial and legal standards under the applicable regulations may qualify and apply for particular blocks made available for concession contracts at each licensing round. Qualified companies may compete alone or in association with other companies, including through the formation of “consortia” (unincorporated joint-ventures), provided they agree to comply with all the applicable requirements of the Brazilian Corporate Law. Blocks awarded and the duration of the exploration and production periods are defined in the contracts which, besides the usual covenants that can be found in oil concessions, such as exploration and development programs, relinquishment of areas, and unitization, include reversion to the state of certain assets at the end of the concession. Contracts may be assigned/transferred to other Brazilian companies that comply with the technical, financial and legal requirements established by ANP.

Concessionaires are required under Law No. 9478 to pay the government dues and fees, in addition to the charges for sale of pre-bid data and information. ANP has the power to determine the criteria under which the Government Take will be assessed within the limits established by Decree No. 2,705/98. Government Take comprises (i) signature bonus, (ii) royalties, (iii) special participation and (iv) area rentals.

Gran Tierra Energy Brasil Ltda (“Gran Tierra Brazil”) received approval by the ANP as a Class B operator permitting Grant Tierra Brazil to act as an operator both onshore and in the shallow water offshore Brazil.

See Item 1A “Risk Factors” for information regarding the regulatory risks that we face.
 
Environmental Compliance
 
Our activities are subject to existing laws and regulations governing environmental quality and pollution control in the foreign countries where we maintain operations. Our activities with respect to exploration, drilling and production from wells, facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing crude oil and other products, are subject to stringent environmental regulation by provincial and federal authorities in Colombia, Argentina, Peru and Brazil. Such regulations relate to environmental impact studies, permissible levels of air and water emissions, control of hazardous wastes, construction of facilities, recycling requirements, reclamation standards, among others. Risks are inherent in oil and gas exploration, development and production operations, and significant costs and liabilities may be incurred in connection with environmental compliance issues. All licenses and permits which we may require to carry out exploration and production activities may not be obtainable on reasonable terms or on a timely basis, and such laws and regulations may have an adverse effect on any project that we may wish to undertake.

In 2011, we plan to spend approximately $5.3 million in Colombia on capital programs related to environmental matters, including facilities upgrades, studies, assessments and remediation. We plan to spend approximately $0.4 million in Argentina on capital programs related to environmental matters, including environmental studies and fire system upgrades. In Peru, capital costs for environmental projects will be about $2.4 million.  In Brazil, we plan to spend approximately $0.1 million on capital costs for environmental projects.
 
In 2010, we experienced a limited number of environmental incidents and enacted many environmental initiatives as follows:
 
 
In Colombia, we dealt with several incidents:

 
In the first quarter of 2010, a faulty truck valve caused a spill of 3.5 barrels on one of the roads in Putumayo and a ruptured injection line at Linda Battery caused the release of 20 barrels contaminating an area of approximately 40 square meters. During the second quarter another truck with a faulty valve caused the contamination of 600 meters of road releasing 35 gallons of oil. A transportation expert was hired to assess the trucking operation and develop a preventive plan. In the third quarter of 2010 an operator failed to follow procedures and released a tanker prior to daylight hours and without the proper checks. Subsequently the tanker was involved in a rollover incident causing the spill of 160 barrels of oil. The total cost of the accident was estimated at $0.5 million. In each of these incidents Gran Tierra completed a full clean-up.

 
Page 14 of 113

 

 
A number of small incidents on our blocks occurred during the year, each of which causing small quantities of oil to be spilled. In each incident Gran Tierra completed a full clean up and remediation of the affected area. Approximately 50 barrels of oil were lost as a result of these incidents.
 
 
In Argentina, EIA's were conducted for the Santa Victoria seismic and Valle Morado drilling programs.
 
 
In Peru, we received EIA approvals for seismic and drilling operations on Block 122 and Block 128.
 
We will continue to strive to be in compliance with all environmental and pollution control laws and regulations in Colombia, Argentina and Peru and also now in Brazil as we commence our initial operations. We plan to continue enacting environmental, health and safety initiatives in order to minimize our environmental impact and expenses. We also plan to continue to improve internal audit procedures and practices in order to monitor current performance and search for improvement.
 
We expect the cost of compliance with Federal, State and local provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment for the remainder of our operations, will not be material to Gran Tierra.

We are in the process of implementing a company wide web based reporting system which will allow Gran Tierra to better track incidents and respective corrective actions and associated costs.  We have a Corporate Health, Safety and Environment Management System and follow Environmental Best Practices. We have an environmental risk management program in place as well as a waste management system. Air and water testing occur regularly, and environmental contingency plans have been prepared for all sites and ground transportation of crude oil. We implemented a regular quarterly comprehensive reporting system in 2009, and continue with a schedule of internal audit and routine checking of practices and procedures. Emergency Response exercises were conducted in Calgary, Argentina, Colombia and Peru.
 
Community Relations

In 2010, we continued standardized, quarterly reporting on our community relations initiatives. We also continuously monitor the needs of the communities where we operate to ensure that our investments meet their requirements and have the highest impact possible.

In addition to employing local people and hiring local companies as often as feasible in all of our operations, we have a program of community investment in all of our operating areas. Projects completed in 2010 are as follows:

Colombia

In 2010, we significantly increased our community relations initiatives and investment, most significantly in the Costayaco field. Below is a description of Gran Tierra’s $1.2 million voluntary social investment, responding to the needs identified and prioritized by the communities in those areas in which we operate.

 
·
Provided support for education through various projects, including providing tuition, supplies, transportation and construction of facilities for students in all levels of education.

 
·
Supported community groups in projects that benefited local families with agriculture and fisheries projects.

 
·
Provided fiscal support, construction of facilities, transportation of materials and other expertise to the projects.

 
·
Various projects for the support of cultural identity such as sponsorship of local festivals that celebrate indigenous culture and history; construction of a workshop for local artisans and community centers; sponsorship of local people to attend a conference of indigenous peoples from various areas in the country.

 
·
Various programs for strengthening local infrastructure such as urban and rural road bridge construction.

 
·
Projects related to health, basic sanitation and housing including improving health facilities, providing supplies to health facilities, providing materials for house construction, constructing community kitchens and community centers, and construction of a local fire station.

 
Page 15 of 113

 
 
Argentina

In Argentina we invested approximately $270,000 in the following projects:

 
·
Provided and distributed education materials to over 19 schools in our operated areas.

 
·
Provided basic life necessities (food, clothing, health support) to impoverished people in our operating areas.

 
·
Delivered medicines to hospitals and supported medical care of children and pregnant women.
 
 
·
Provided temporary employment to residents in several of our operating areas.

 
·
Provided funds in support of beekeeping and crafts projects.

 
·
Along with our joint venture partners in the Palmar Largo Block, several other initiatives were undertaken, including projects aimed at developing sustainable income for the communities in the area, fuel and security for local hospitals, and construction of reservoirs and water wells. These projects were operated by PlusPetrol S.A.

Peru

In Peru, we invested $585,200 in the following projects:

 
·
Negotiated a compensation program with communities for use of their lands.

 
·
Provided consultation and education sessions with various communities located on our two blocks.

 
·
Provided community training for environmental preservation.

 
·
Provided healthcare support services to communities in our blocks.

 
·
Provided community policing and monitoring services in communities in our blocks.

 
·
Provided temporary employment to residents in our blocks.

Brazil

We plan to spend approximately $140,000 for consulting services related to environmental initiatives on our new block.

Employees
 
At December 31, 2010, we had 307 full-time employees — 29 located in the Calgary corporate office, 210 in Colombia (103 staff in Bogota and 107 field personnel), 49 in Argentina (26 office staff in Buenos Aires and 23 field personnel), 15 in Peru (both field and office staff) and 4 in Brazil, all office staff. None of our employees are represented by labor unions, and we consider our employee relations to be good.
 
Item 1A. Risk Factors
 
Risks Related to Our Business

Our Lack of Diversification Will Increase the Risk of an Investment in Our Common Stock. 
 
Our business focuses on the oil and gas industry in a limited number of properties in Colombia, Argentina, Peru, and Brazil.  Most of our production in Colombia and Argentina is limited to one basin per country.  As a result, we lack diversification, in terms of both the nature and geographic scope of our business.  Accordingly, factors affecting our industry or the regions in which we operate, including the geographic remoteness of our operations and weather conditions, will likely impact us more acutely than if our business was more diversified.

 
Page 16 of 113

 

We May Encounter Difficulties Storing and Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses. 
 
To sell the oil and natural gas that we are able to produce, we have to make arrangements for storage and distribution to the market. We rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. In certain areas, we may be required to rely on only one gathering system, trucking company or pipeline, and, if so, our ability to market our production would be subject to their reliability and operations. These factors may affect our ability to explore and develop properties and to store and transport our oil and gas production, and may increase our expenses.

Furthermore, future instability in one or more of the countries in which we operate, weather conditions or natural disasters, actions by companies doing business in those countries, labor disputes or actions taken by the international community may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.
 
The majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol and sales of oil could be disrupted by damage to this pipeline. Once delivered to Ecopetrol, all of our current oil production in Colombia is transported by an export pipeline which provides the only access to markets for our oil. Problems with these pipelines can cause interruptions to our producing activities if they are for a long enough duration that our storage facilities become full. For example, we experienced disruptions in transportation on this pipeline in March and April of 2008, again in each of June, July and August of 2009, again in June, August, and September 2010, and again in February 2011 as a result of sabotage by guerrillas. In addition, there is competition for space in these pipelines, and additional discoveries in our area of operations by other companies could decrease the pipeline capacity available to us.  Trucking is an alternative to transportation by pipeline; however it is generally more expensive and carries higher safety risks for the company and the public.

As the majority of current oil production in Argentina is trucked to a local refinery, sales of oil can be delayed by adverse weather and road conditions, particularly during the months November through February when the area is subject to periods of heavy rain and flooding. While storage facilities are designed to accommodate ordinary disruptions without curtailing production, delayed sales will delay revenues and may adversely impact our working capital position in Argentina. Furthermore, a prolonged disruption in oil deliveries could exceed storage capacities and shut-in production, which could have a negative impact on future production capability.

Guerrilla Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned About Safeguarding Our Operations and Personnel in Colombia.   

Despite significant recent security gains, Colombia remains a country where safety is a significant concern. For over 40 years, the government has been engaged in a civil war with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia (FARC) and the National Liberation Army (ELN). Both of these groups have been designated as terrorist organizations by the United States and the European Union. In recent years, however, the government has successfully dissolved the AUC militia, a paramilitary group that originally sprouted up to combat the FARC and ELN. The dissolved AUC militia members have reorganized in the form of criminal gangs.

We operate principally in the Putumayo basin  in Colombia, and have properties in other basins, including the Catatumbo, Llanos, Middle Magdalena and Lower Magdalena basins. The Putumayo and Catatumbo regions have been prone to guerilla activity. In 1989, our predecessor company’s facilities in one field were attacked by guerillas and operations were briefly disrupted. Again on 16 October 2010, two of our sites in the Putumayo/Cauca were attacked by FARC guerillas causing some disruption to operations. Pipelines have also been targets, including the Ecopetrol - operated Trans Andean (OTA) export pipeline which transports oil from the Putumayo region. In March and April of 2008, again in each of June, July, August and October of 2009, again in June, August, and September 2010, and again in February 2011, sections of the Trans Andean pipeline were sabotaged by guerillas, which temporarily reduced our deliveries to Ecopetrol during the affected periods.

Continuing attempts by the Colombian Government to reduce or prevent guerilla activity may not be successful and guerilla activity may disrupt our operations in the future. There can also be no assurance that we can maintain the safety of our operations and personnel in Colombia or that this violence will not affect our operations in the future and cause significant loss.

Our Business May Suffer If We Do Not Attract and Retain Talented Personnel. 

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our executive team and other personnel in conducting the business of Gran Tierra. The loss of any of these individuals or our inability to attract suitably qualified individuals to replace any of them could materially adversely impact our business. We may also experience difficulties in certain jurisdictions in our efforts to obtain suitably qualified staff and retain staff that are willing to work in that jurisdiction. We do not currently carry life insurance for our key employees.

 
Page 17 of 113

 

Our success depends on the ability of our management and employees to interpret market and geological data successfully and to interpret and respond to economic, market and other business conditions in order to locate and adopt appropriate investment opportunities, monitor such investments and ultimately, if required, successfully divest such investments. Further, our key personnel may not continue their association or employment with Gran Tierra and we may not be able to find replacement personnel with comparable skills. If we are unable to attract and retain key personnel, our business may be adversely affected. 

Our Oil Sales Will Depend on a Relatively Small Group of Customers, Which Could Adversely Affect Our Financial Results. 

Oil sales in Colombia are mainly to Ecopetrol. While oil prices in Colombia are related to international market prices, lack of competition and reliance on a limited number of customers for sales of oil may diminish prices and depress our financial results.

The entire Argentine domestic refining market is small and export opportunities are limited by available infrastructure. As a result, our oil sales in Argentina will depend on a relatively small group of customers, and currently, on just one customer. The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results.  Currently all operators in Argentina are operating without sales contracts. We cannot provide any certainty as to when the situation will be resolved or what the final outcome will be.  
 
Strategic Relationships Upon Which We May Rely are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.    
 
Our ability to successfully bid on and acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements will depend on developing and maintaining effective working relationships with industry participants and on our ability to select and evaluate suitable partners and to consummate transactions in a highly competitive environment. These relationships are subject to change and may impair Gran Tierra’s ability to grow.

To develop our business, we endeavor to use the business relationships of our management and board of directors to enter into strategic relationships, which may take the form of joint ventures with other private parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may choose the wrong partner or we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to take to fulfill our obligations to these partners or maintain our relationships. If we fail to make the cash calls required by our joint venture partners in the joint ventures we do not operate, we may be required to forfeit our interests in these joint ventures.  If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

In addition, in cases where we are the operator, our partners may not be able to fulfill their obligations, which would require us to either take on their obligations in addition to our own, or possibly forfeit our rights to the area involved in the joint venture. In addition, despite our partner’s failure to fulfill its obligations, if we elect to terminate such relationship, we may be involved in litigation with such partners or may be required to pay amounts in settlement to avoid litigation despite such partner’s failure to perform.  Alternatively, our partners may be able to fulfill their obligations, but will not agree with our proposals as operator of the property.  In this case there could be disagreements between joint venture partners that could be costly in terms of dollars, time, deterioration of the partner relationship, and/or our reputation as a reputable operator.  These joint venture partners may not comply with their responsibilities or may engage in conduct that could result in liability to Gran Tierra.

In cases where we are not the operator of the joint venture, the success of the projects held under these joint ventures is substantially dependent on our joint venture partners. The operator is responsible for day-to-day operations, safety, environmental compliance and relationships with government and vendors.

We have various work obligations on our blocks that must be fulfilled or we could face penalties, or lose our rights to those blocks if we do not fulfill our work obligations.  Failure to fulfill obligations in one block can also have implications on the ability to operate other blocks in the country ranging from delays in government process and procedure to loss of rights in other blocks or in the country as a whole.  Failure to meet obligations in one particular country may also have an impact on our ability to operate in others.

Our Business is Subject to Local Legal, Political and Economic Factors Which are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably.   
 
We operate our business in Colombia, Argentina, Peru, and Brazil, and may eventually expand to other countries in the world. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, social unrest, strikes by local or national labor groups, interference with private contract rights (such as privatization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. For example, starting on November 21, 2008, we were forced to reduce production in Colombia on a gradual basis, culminating on December 11, 2008 when we suspended all production from the Santana, Guayuyaco and Chaza blocks in the Putumayo Basin.  This temporary suspension of production operations was the result of a declaration of a state of emergency and force majeure by Ecopetrol due to a general strike in the region. In January 2009, the situation was resolved and we were able to resume production and sales shipments. In 2010, there has been an increased presence of illegitimate unionization activities in the Putumayo Basin by the Sindicato de Trabajadores Petroleros del Putumayo (“Sintrapetorputumayo”), which has disrupted our operations from time to time and may do so in the future.

 
Page 18 of 113

 
 
South America has a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. Any changes in oil and gas or investment regulations and policies or a shift in political attitudes in Argentina, Colombia, Peru or Brazil or other countries in which we intend to operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.
  
For instance, changes in laws in the jurisdiction in which we operate or expand into with the effect of favoring local enterprises, and changes in political views regarding the exploitation of natural resources and economic pressures, may make it more difficult for us to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations. In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. Property right transfers, joint ventures, licenses, license applications or other legal arrangements pursuant to which we operate may be adversely affected by the actions of government authorities and the effectiveness of and enforcement of our rights under such arrangements in these jurisdictions may be impaired.

Foreign Currency Exchange Rate Fluctuations May Affect Our Financial Results. 
 
We expect to sell our oil and natural gas production under agreements that will be denominated in United States dollars and foreign currencies. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. Our production in Argentina is primarily invoiced in United States dollars, but payment is made in Argentine pesos, at the then-current exchange rate. As a result, we are exposed to translation risk when local currency financial statements are translated to United States dollars, our company’s functional currency. Since we began operating in Argentina (September 1, 2005), the rate of exchange between the Argentine peso and US dollar has varied between 3.05 pesos to one US dollar to 3.96 pesos to the US dollar, a fluctuation of approximately 30%. Exchange rates between the Colombian peso and US dollar have varied between 2,632 pesos to one US dollar to 1,648 pesos to one US dollar since September 1, 2005, a fluctuation of approximately 60%.

In addition, a foreign exchange loss of $18.7 million, of which $14.8 million is an unrealized non-cash foreign exchange loss, was recorded in 2010 and was primarily due to the translation of a deferred tax liability recorded on the purchase of Solana. The deferred tax liability is denominated in Colombian pesos and the devaluation of 6% in the US dollar against the Colombian Peso in the year ended December 31, 2010 resulted in the foreign exchange loss.

Exchange Controls and New Taxes Could Materially Affect our Ability to Fund Our Operations and Realize Profits from Our Foreign Operations.   
 
Foreign operations may require funding if their cash requirements exceed operating cash flow. To the extent that funding is required, there may be exchange controls limiting such funding or adverse tax consequences associated with such funding. In addition, taxes and exchange controls may affect the dividends that we receive from foreign subsidiaries.

Exchange controls may prevent us from transferring funds abroad. For example, the Argentine government has imposed a number of monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by the Argentine Central Bank. The Central Bank may require prior authorization and may or may not grant such authorization for our Argentine subsidiaries to make dividend payments to us and there may be a tax imposed with respect to the expatriation of the proceeds from our foreign subsidiaries.

Competition in Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair Our Business.   
 
The oil and gas industry is highly competitive. Other oil and gas companies will compete with us by bidding for exploration and production licenses and other properties and services we will need to operate our business in the countries in which we expect to operate. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger, foreign owned companies, which, in particular, may have access to greater resources than us, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. In the event that we do not succeed in negotiating additional property acquisitions, our future prospects will likely be substantially limited, and our financial condition and results of operations may deteriorate.

 
Page 19 of 113

 

Maintaining Good Community Relationships and Being a Good Corporate Citizen may be Costly and Difficult to Manage.

Our operations have a significant effect on the areas in which we operate. To enjoy the confidence of local populations and the local governments, we must invest in the communities where were operate. In many cases, these communities are impoverished and lack many resources taken for granted in North America. The opportunities for investment are large, many and varied; however, we must be careful to invest carefully in projects that will truly benefit these areas. Improper management of these investments and relationships could lead to a delay in operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business.
 
Our Operations Involve Substantial Costs and are Subject to Certain Risks Because the Oil and Gas Industries in the Countries in Which We Operate are Less Developed.   
 
The oil and gas industry in South America is not as efficient or developed as the oil and gas industry in North America. As a result, our exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. We expect that such factors will subject our international operations to economic and operating risks that may not be experienced in North American operations. 

Negative Political and Regulatory Developments in Argentina May Negatively Affect our Operations.
 
The crude oil and natural gas industry in Argentina is subject to extensive regulation including land tenure, exploration, development, production, refining, transportation, and marketing, imposed by legislation enacted by various levels of government and, with respect to pricing and taxation of crude oil and natural gas, by agreements among the federal and provincial governments, all of which are subject to change and could have a material impact on our business in Argentina. The Federal Government of Argentina has implemented controls for domestic fuel prices and has placed a tax on crude oil and natural gas exports.

In October 2010, ENARGAS issued Regulation I-1410 aiming at securing the supply of natural gas to residential consumers and small industry given the decline in gas production and the expected growing demand for gas.  The regulation includes all the procedures created by the authorities since 2004 (restrictions of exports, deviation of gas sales, to residential consumption) and gives ENARGAS power to control gas marketing in order to assure the supply of gas to residential consumers and small industry.

Any future regulations that limit the amount of oil and gas that we could sell or any regulations that limit price increases in Argentina and elsewhere could severely limit the amount of our revenue and affect our results of operations.

Currently most oil and gas producers in Argentina are operating without sales contracts. In 2008, a new withholding tax regime for exports was introduced without specific guidance as to its application. The domestic price was regulated in a similar way, so that both exported and domestically sold products were priced the same. Producers and refiners of oil in Argentina were unable to determine an agreed sales price for oil deliveries to refineries. In our case, the refineries’ price offered to oil producers reflects their price received, less taxes and operating costs and their usual mark up. Along with most other oil producers in Argentina, we are continuing negotiating sales on a spot price basis with one refiner, Refinor S.A., and the price is negotiated on a month by month basis. The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced and capital investment in oilfields has declined, and so they are lobbying to change the situation. We are working with other oil and gas producers in the area, as well as Refinor S.A., to lobby the federal government for change. The government introduced the Petro Plus and Gas Plus programs in 2009, which grant higher prices to producers that sell production from new reserves. This is a positive step forward that will hopefully lead to further opening of price regulation in Argentina.

The United States Government May Impose Economic or Trade Sanctions on Colombia That Could Result In A Significant Loss To Us.   
 
Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future.  A finding by the President that Colombia has failed demonstrably to meet its obligations under international counternarcotics agreements may result in any of the following:
 
all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended;

the Export-Import Bank of the United States and the Overseas Private Investment Corporation would not approve financing for new projects in Colombia;

United States representatives at multilateral lending institutions would be required to vote against all loan requests from Colombia, although such votes would not constitute vetoes; and

the President of the United States and Congress would retain the right to apply future trade sanctions.

 
Page 20 of 113

 

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with ANH and Ecopetrol and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. The United States may impose sanctions on Colombia in the future, and we cannot predict the effect in Colombia that these sanctions might cause.
 
We May Be Unable to Obtain Additional Capital That We Will Require to Implement Our Business Plan, Which Could Restrict Our Ability to Grow.   
 
We expect that our existing cash resources will be sufficient to fund our currently planned activities. We may require additional capital to expand our exploration and development programs to additional properties. We may be unable to obtain additional capital required.

When we require additional capital we plan to pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do succeed in raising additional capital, future financings may be dilutive to our stockholders, as we could issue additional shares of common stock or other equity to investors. In addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which will adversely impact our financial results.

Our ability to obtain needed financing may be impaired by factors such as the capital markets (both generally and in the oil and gas industry in particular), the location of our oil and natural gas properties in South America, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us), and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. If the amount of capital we are able to raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to curtail our operations.
 
We May Not Be Able To Effectively Manage Our Growth, Which May Harm Our Profitability. 
 
Our strategy envisions continually expanding our business, both organically and through acquisition of other properties and companies. If we fail to effectively manage our growth or integrate successfully our acquisitions, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new or acquired employees. We may not be able to:

 
expand our systems effectively or efficiently or in a timely manner;

 
allocate our human resources optimally;

 
identify and hire qualified employees or retain valued employees; or

 
incorporate effectively the components of any business that we may acquire in our effort to achieve growth.
 
If we are unable to manage our growth and our operations our financial results could be adversely affected by inefficiencies, which could diminish our profitability.

 
Page 21 of 113

 

Risks Related to Our Industry

Unless We are Able to Replace Our Reserves, and Develop Oil and Gas Reserves on an Economically Viable Basis, Our Reserves, Production and Cash Flows May Decline as a Result.   
 
Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. We may not be able to find, develop or acquire additional reserves at acceptable costs.

To the extent that we succeed in discovering oil and/or natural gas, reserves may not be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our company’s viability depends on our ability to find or acquire, develop and commercially produce additional oil and gas reserves. Without the addition of reserves through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we may not be able to do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We are Required to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain These Licenses or to Obtain Them on a Timely Basis Could Cause Significant Delays and Expenses That Could Materially Impact Our Business.   
 
We are subject to licensing and permitting requirements relating to exploring and drilling for and development of oil and natural gas, including seismic permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations.
 
Our Exploration for Oil and Natural Gas Is Risky and May Not Be Commercially Successful, Impairing Our Ability to Generate Revenues from Our Operations.   
 
Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our exploration expenditures may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.
 
Estimates of Oil and Natural Gas Reserves that We Make May Be Inaccurate and Our Actual Revenues May Be Lower and Our Operating Expenses May Be Higher than Our Financial Projections.   
 
We make estimates of oil and natural gas reserves, upon which we will base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as interest rates and exchange rates, will also impact the value of our reserves. The process of estimating oil and gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

 
Page 22 of 113

 

Exploration, development, production, marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and gas that we produce. These costs are subject to fluctuations and variation in different locales in which we operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

If Oil and Natural Gas Prices Decrease, We May be Required to Take Write-Downs of the Carrying Value of Our Oil and Natural Gas Properties.
 
We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period for that oil and natural gas.  That average price is then held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.  In 2010, we recorded a ceiling test impairment loss of $23.6 million in our Argentina cost center.

Drilling New Wells and Producing Oil and Natural Gas from Existing Facilities Could Result in New Liabilities, Which Could Endanger Our Interests in Our Properties and Assets. 
 
There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. Earthquakes or weather related phenomena such as heavy rain, landslides, storms and hurricanes can also cause problems in drilling new wells.  There are also risks in producing oil and natural gas from existing facilities. For example, the Valle Morado GTE.St.VMor-2001 re-entry operations started in the third quarter of 2010, with integrity testing and remediation operations required for the sidetrack operations. Due to operational difficulties, the initial side-track attempt was not successful. The operation was placed on standby pending the arrival of additional side-track equipment and operations recommenced in fourth quarter of 2010.   In February 2011, these operations were suspended and the wellbore will be abandoned due to a number of operational challenges encountered.  Gran Tierra Energy continues to review alternatives associated with the field development.  Also for example, on February 7, 2009 we experienced an incident at our Juanambu 1 well, involving a fire in a generator, resulting in total damage to equipment estimated at $500,000, and production in the amount of approximately $125,000 being deferred due to shutting down production facilities while dealing with the incident. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. Incidents such as these can lead to serious injury, property damage and even loss of life.  We generally obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Our Inability to Obtain Necessary Facilities and/or Equipment Could Hamper Our Operations. 
 
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities or equipment may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities or equipment may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.
 
Decommissioning Costs Are Unknown and May be Substantial; Unplanned Costs Could Divert Resources from Other Projects.  
 
We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have determined that we require a reserve account for these potential costs in respect of our current properties and facilities at this time, and have booked such reserve on our financial statements. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy decommissioning costs could impair our ability to focus capital investment in other areas of our business.

 
Page 23 of 113

 

Prices and Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate Significantly, Which Could Reduce Profitability, Growth and the Value of Gran Tierra.   
 
Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for WTI per barrel was $66 in 2006, $72 in 2007, $100 in 2008, $62 in 2009, and $79 in 2010, demonstrating the inherent volatility in the market. We expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our oil and gas reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry.  Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differentials. These differentials can change over time and have a detrimental impact on realized prices. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.
 
In addition, oil and natural gas prices in Argentina are effectively regulated and during 2009 and 2010 were substantially lower than those received in North America. Oil prices in Colombia are related to international market prices, but adjustments that are defined by contract with Ecopetrol, the purchaser of most of the oil that we produce in Colombia, may cause realized prices to be lower than those received in North America.

Penalties We May Incur Could Impair Our Business. 
 
Our exploration, development, production and marketing operations are regulated extensively under foreign, federal, state and local laws and regulations. Under these laws and regulations, we could be held liable for personal injuries, property damage, site clean-up and restoration obligations or costs and other damages and liabilities. We may also be required to take corrective actions, such as installing additional safety or environmental equipment, which could require us to make significant capital expenditures. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. We could be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result of these laws and regulations, our future business prospects could deteriorate and our profitability could be impaired by costs of compliance, remedy or indemnification of our employees, reducing our profitability.

Policies, Procedures and Systems to Safeguard Employee Health, Safety and Security May Not be Adequate.

Oil and natural gas exploration and production is dangerous.  Detailed and specialized policies, procedures and systems are required to safeguard employee health, safety and security.  We have undertaken to implement best practices for employee health, safety and security; however, if these policies, procedures and systems are not adequate, or employees do not receive adequate training, the consequences can be severe including serious injury or loss of life, which could impair our operations and cause us to incur significant legal liability.
 
Environmental Risks May Adversely Affect Our Business. 
 
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and federal, provincial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to foreign governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.
 
Our Insurance May Be Inadequate to Cover Liabilities We May Incur. 
 
Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we have insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

 
Page 24 of 113

 

Challenges to Our Properties May Impact Our Financial Condition. 
 
Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interest in and to the properties to which the title defects relate. 
 
Furthermore, applicable governments may revoke or unfavorably alter the conditions of exploration and development authorizations that we procure, or third parties may challenge any exploration and development authorizations we procure. Such rights or additional rights we apply for may not be granted or renewed on terms satisfactory to us.
 
If our property rights are reduced, whether by governmental action or third party challenges, our ability to conduct our exploration, development and production may be impaired.
  
We Will Rely on Technology to Conduct Our Business and Our Technology Could Become Ineffective Or Obsolete. 
 
We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration and development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.
 
Risks Related to Our Common Stock 
 
The Market Price of Our Common Stock May Be Highly Volatile and Subject to Wide Fluctuations. 
 
The market price of our common stock may be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including but not limited to:

dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with acquisitions of other companies or assets;

announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

fluctuations in revenue from our oil and natural gas business;

changes in the market and/or WTI price for oil and natural gas commodities and/or in the capital markets generally;

changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels; and

changes in the social, political and/or legal climate in the regions in which we will operate.
 
In addition, the market price of our common stock could be subject to wide fluctuations in response to various factors, which could include the following, among others:

quarterly variations in our revenues and operating expenses;

changes in the valuation of similarly situated companies, both in our industry and in other industries;

changes in analysts’ estimates affecting our company, our competitors and/or our industry;

changes in the accounting methods used in or otherwise affecting our industry;

additions and departures of key personnel;

announcements of technological innovations or new products available to the oil and natural gas industry;

announcements by relevant governments pertaining to incentives for alternative energy development programs;

 
Page 25 of 113

 

fluctuations in interest rates, exchange rates and the availability of capital in the capital markets; and
 
 
significant sales of our common stock, including sales by future investors in future offerings we expect to make to raise additional capital.
   
These and other factors are largely beyond our control, and the impact of these risks, singularly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our results of operations and financial condition.
 
We Do Not Expect to Pay Dividends In the Foreseeable Future. 
 
We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.
 
Item 1B. Unresolved Staff Comments
 
Not applicable.
 
Item 2. Properties

Offices

We currently lease office space in: Calgary, Alberta; Buenos Aires and Vespucio, Argentina; Bogota, Colombia; Rio de Janiero, Brazil; and Lima and Iquitos, Peru.

We have five Calgary leases, the first two expire January 31, 2013, the third expires October 31, 2012, the fourth expires April 30, 2014 and the fifth expires on October 30, 2015.  Their cost is $12,305 per month, $6,641 per month, $4,087 per month, $13,224 per month and $34,278 per month respectively. We have subleased the first lease for $4,444 per month from February 1, 2011 to January 30, 2013 to a company for which our President and Chief Executive Officer serves as an independent Director.  We have subleased the third lease for $3,794 per month from July 1, 2010 to October 29, 2012 and the fourth lease for $12,125 per month from February 1, 2009 to August 31, 2011. We plan on subleasing the second as well. Since March 2010, all Calgary staff is housed in the space covered by our fifth sub-lease.

Our three Buenos Aires, Argentina leases expire January 31, 2012, March 7, 2012 and July 17, 2012 and cost $2,877 per month, $2,455 per month and $2,743 per month respectively. We also have a lease in Vespucio, Argentina which expires February 28, 2011 and has a cost of $946 per month.

We have two leases in Bogotá, Colombia. They expire February 28, 2011 and February 1, 2012 and cost $2,029 per month and $87,065 per month, respectively.

We have office space leased in Rio de Janeiro, Brazil until September 30, 2012 at a cost of $12,380 per month.

In Lima, Perú, we have one office lease expiring August 31, 2014 at a cost of $8,229 per month and two houses for staff residences with leases expiring June 1 2012 and August 2, 2012 with a cost of $2,350 per month and $1,200 per month respectively. In Iquitos, Perú, we have a combination office and staff residence and an additional staff residence with leases expiring October 31, 2011 and September 8, 2012 at a cost of $1,055 per month, and $534 per month, respectively. The properties remaining on lease are in good condition and we believe that they are sufficient for our office needs for the foreseeable future.
 
Oil and Gas Properties – Colombia

In June 2006, we purchased Argosy Energy International L.P (“Argosy”) which was subsequently renamed Gran Tierra Colombia Ltd. Argosy had interests in seven exploration and production contracts at that time, including the Santana, Guayuyaco, Chaza and Mecaya blocks in the Putumayo basin in southwest Colombia; the Talora and Rio Magdalena blocks in the Magdalena basin, west of Bogota; and the Primavera Block 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 two Technical Evaluation Areas in the Putumayo basin (Putumayo West A and Putumayo West B) were acquired in 2007. We relinquished the Primavera Block in 2007 and we relinquished the Talora Block in 2009.

In November 2008, we acquired Solana which increased our interest in the Guayuyaco and Chaza blocks, and added 7 blocks in 3 basins. The Magangue Block is located in the Lower Magdalena basin in northwest Colombia; the Catguas Block is in the Catatumbo basin which forms the southwest flank of Venezuela’s Maracaibo basin; and the Guachiria Norte, San Pablo, Guachiria, Guachiria Sur and Garibay blocks are in the Llanos basin north east of Bogota. In 2009, we sold the Guachira, Guachiria Sur and Guachiria Norte blocks and we relinquished our rights to the San Pablo Block.

 
Page 26 of 113

 

In 2009, we converted portions of the two Technical Evaluation Areas to three exploration and production blocks – part of Putumayo West A was converted to two exploration and exploitation blocks named Piedemonte Norte and Piedemonte Sur. Part of Putumayo West B was converted to the Rumiyaco Block.

In 2010, we were awarded 3 blocks in Colombia Bid Round 10 which are subject to ANH approval (Cauca 6, Cauca 6 and Putumayo-10).  In 2010, we also acquired an operated interest in the Putumayo-1 Block.  We currently have interests in 16 blocks in Colombia, and are operator of 15 blocks.

Currently, the Guayuyaco, Santana, Chaza and Garibay blocks have producing oil wells.  The Magangue Block has 1 producing gas well.

Colombian royalties are established under law 756 of 2002. All discoveries made subsequent to the enactment of this law have the sliding scale royalty described below. Discoveries made before the enactment of this law have a royalty of 20%. The ANH contracts to which Gran Tierra is a party all have royalties that are based on a sliding scale described in law 756. This royalty works on an individual field basis starting with a base royalty rate of 8% for gross production of less than 5,000 barrels of oil per day. The royalty increases in a linear fashion from 8% to 20% for gross production between 5,000 and 125,000 barrels of oil per day, and is stable at 20% for gross production between 125,000 and 400,000 barrels of oil per day. For gross production between 400,000 and 600,000 barrels of oil per day the rate increases in a linear fashion from 20% to 25%. For gross production in excess of 600,000 barrels of oil per day the royalty rate is fixed at 25%. Our production from the Costayaco field is also subject (starting in October 2009) to an additional royalty that applies when cumulative gross production from a field is greater than 5 million barrels. This additional royalty applies to 30% of the gross production and is calculated on the difference between WTI and an oil quality based index. As the law stands currently, any new discoveries on ANH contracted blocks will also be subject to this additional royalty once each new field exceeds 5 million barrels of cumulative production.  The Moqueta discovery in the Chaza Block and the Jilguero discovery in the Garibay Block will both be subject to this additional royalty after each field produces 5 million barrels.  The Santana and Magangue blocks have a flat 20% royalty as those discoveries were made before 2002. The Guayuyaco and Rio Magdalena blocks have the sliding scale royalty but do not have the additional royalty. In addition to these government royalties, Gran Tierra’s original interests in the five blocks purchased from Argosy that we still hold (Santana, Guayuyaco, Chaza, Rio Magdalena, Mecaya) are subject to a third party royalty. The additional interest in Guayuyaco and Chaza acquired by Gran Tierra on the acquisition of Solana is not subject to this third party royalty.
 
Santana Block

The Santana Block contract was signed in July 1987 and covers 1,119 gross acres and includes 14 producing wells in four fields — Linda, Mary, Miraflor and Toroyaco. Activities are governed by terms of a Shared Risk Contract with Ecopetrol, and we are the operator. We hold a 35% working interest in all fields. Ecopetrol holds the remaining interest. The block has been producing since 1991. Under the Shared Risk Contract, Ecopetrol initially backed in to a 50% working interest upon declaration of commerciality in 1991. In June 1996, when the block reached 7 million barrels of oil produced, Ecopetrol had the right to back into a further 15% working interest, 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 2010, we performed minor facility maintenance. For 2011 there are no capital expenditures planned for Santana.
 
Guayuyaco Block
 
The Guayuyaco Block contract was signed in September 2002 and covers 52,366 gross acres, which includes the area surrounding the four producing fields of the Santana contract area. The Guayuyaco Block is governed by an Association Contract with Ecopetrol. We are the operator and have a 70% participation interest, with the other 30% held by Ecopetrol. The Guayuyaco field was discovered in 2005. Two wells are now producing in this field, Guayuyaco-1 commenced production in February 2005 and Guayuyaco-2 began production in September 2005.  The Juanambu field, also in the Guayuyaco Block has two producing wells; Juanambu-1 began commercial production on November 8, 2007 and Juanambu-2 began production in March 2010.  Ecopetrol has the option to back-in to a 30% participation interest in any other 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 2030. We have completed all of our obligations in relation to the exploration phase of the contract. The property will be returned to the government upon expiration of the production contract. As a result, there will be no reclamation costs.
 
In 2010, we drilled Juanambu -2 and we also performed work on electrical systems, flowlines, storage tanks and other production facilities. In 2011, we plan to drill one development well (Juanambu-3) and conduct two exploration 3D seismic programs.

 
Page 27 of 113

 

Chaza Block
 
The Chaza Block covers 80,242 gross acres and is governed by the terms of an Exploration and Exploitation Contract with ANH, which was signed June 27, 2005. We are the operator and hold a 100% 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.

This block entered the 6th exploration phase in December 2010 which has a six month duration and an obligation to drill one exploration well.  The contract for this field expires in two phases. The exploration phase currently expires in 2011 and the production phase ends in 2033. The property will be returned to the government upon expiration of the production phase. We are planning to apply for an additional exploratory program allowable under our contract which would extend the exploration phase of the contract for an additional four years. Within 60 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.

In 2010, we drilled one successful exploration well,  and plugged and abandoned  a second exploration well, Dantayaco-1.  Pacayaco-1 was suspended while we acquired and interpreted additional seismic and either a new well or a sidetrack of the existing well is planned late in the second quarter of 2011.  In the Costayaco field, Costayaco-11 was drilled as a development well and the Costayaco-12 and Costayaco-13 development wells were in progress at year-end.  We performed upgrades to the pumping station, battery and support facilities and initiated a project to electrify the field.  The electrification will reduce our dependence on diesel fuel for power and lead to cost savings.  In the Moqueta field, we drilled three delineation wells, Moqueta-2, 3 and 4 (in progress at year end and testing expected to be completed by March 2011).  Two seismic programs were acquired in the Chaza Block; the Rio Guineo 100 square kilometer 3D program and the Moqueta 50 kilometer 2D program.

In 2011, one exploration well is planned for the Chaza Block, Canangucho-1 (spud February 2011), and up to three development wells.  One water injector well is planned for the Costayaco field and up to two development wells are planned for the Moqueta field (Moqueta 5 and 6).  The remaining facility upgrades in the Costayaco field are planned to be completed in 2011.  In addition, the Moqueta pipeline and production facilities are planned to be completed with the expectation of initial production early in the second quarter of 2011.  Two seismic acquisition programs are planned for 2011; the Moqueta 120 square kilometer 3D program and the Verdeyaco 3D program.
 
Azar Block
 
We acquired an 80% interest in the Azar Block through a farm-in agreement entered into in late 2006. This exploration block covers 47,226 gross acres and we are the operator.  Pursuant to the terms of the farm-in agreement we were obligated to pay the original owner’s 20% share of future costs, in addition to 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 periods of the exploration contract, and we remained obligated to pay 20% of costs under our 2006 farm-in agreement. The agreement has now moved to its next phase, in which the carried partner will pay 50% of its share (10% of the total cost) of the work for the current exploration period to maintain its 20% interest. If the carried partner does not pay its share of the costs, then it will reduce its ownership percentage to 10%. We are now in the fourth exploration period which carries a commitment to drill one well. There are two more exploration periods that follow, each lasting 12 months and including an obligation to drill one exploration well. The exploration phase of the contract expires in 2013 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.

In 2010, we acquired 75 square kilometers of 3D seismic.  In 2011, we plan to drill one exploration well.

Piedemonte Norte Block

In June 2009, we completed the conversion of our Technical Evaluation Areas in the Putumayo Basin to blocks with ANH Exploration and Exploitation Contracts. Piedemonte Norte covers 78,742 gross acres and is held 100% by Gran Tierra and was part of the Putumayo West A Technical Evaluation Area. From June to December 2009 we were in a pre-exploration phase in which we performed environmental evaluation and survey work. The first exploration period expires in June 2011.  There are a total of 6 exploration periods and the exploration phase of the contract expires in December 2015.  The exploitation phase would expire 24 years after commerciality of a discovery is approved. The first exploration period contains a commitment to acquire, process and interpret 70 kilometers of 2D seismic by June 2011.

In 2010, we acquired 20 kilometers of 2D seismic.  In 2011, we plan to acquire 50 kilometers of 2D seismic and drill one stratigraphic well.

 
Page 28 of 113

 

Piedemonte Sur Block

Piedemonte Sur was also part of the Putumayo West A Technical Evaluation Area and became an exploration block with an ANH Exploration and Exploitation Contract in June 2009. Piedemonte Sur covers 73,898 gross acres and is held 100% by Gran Tierra. From June to December 2009, we were in a pre-exploration phase in which we performed environmental evaluation and survey work. We are now in the first exploration period of a total of six periods in the contract. The exploration phase ends in December 2015, and the exploitation phase would expire 24 years after commerciality of a discovery is approved. The first exploration period contains a commitment to drill one exploration well to a minimum depth of 3,000 feet, by December 16, 2010.

In 2010, we acquired 20 kilometers of 2D seismic and this program extended into 2011.  In 2011, we plan to complete the 2D seismic acquisition program and drilling of the first exploration well.  Pre-drill operations for this exploratory well, Taruka–1, were in progress at year-end and formal extension of the first phase was requested from the ANH.   Taruka-1 was spud in early January 2011 and plugged and abandoned in February 2011.

Rumiyaco Block

Rumiyaco was part of the Putumayo West B Technical Evaluation Area and became an exploration block with an ANH Exploration and Exploitation Contract in June 2009. Rumiyaco covers 82,624 gross acres and is held 100% by Gran Tierra. From June to December 2009, we were in a pre-exploration phase in which we performed environmental evaluation and survey work. We are now in the second exploration period of a total of six periods in the contract. The exploration phase ends in December 2015, and the exploitation phase would expire 24 years after commerciality of a discovery is approved. The second exploration period contains a commitment to drill one exploration by September 2011.

In 2010, we acquired 95 square kilometers of 3D seismic.   In 2011, we plan to drill one exploration well (Rumiyaco-1).

Magangué Block

Solana acquired the Magangue Block in October 2006. It is held pursuant to an Ecopetrol Association Contract and covers an area of 20,647 gross acres. We are the operator of the block with a 42% working interest and our partner Ecopetrol has the remaining 58%. This block contains the Güepajé gas field.

This block borders the La Creciente Block where there was a significant gas discovery in the same productive formation as the Güepajé gas field in 2006. The contract expires in 2017. The exploration phase for this block is over and there are no obligatory work commitments.

In 2010, we purchased equipment for hydrocarbon dew point control to meet pipeline specifications.   In 2011, we plan to do minor facility upgrades.

Garibay Block

Solana acquired the Garibay Block in October 2005. The block covers 75,936 gross acres and we have a working interest of 50%. The block is located approximately 170 kilometers east of Bogotá and is subject to an ANH contract. On November 17, 2007, a farm-out agreement was signed with a third party under which they financed the drilling of the Topocho-1 exploration well in return for a 50% working interest in the block and becoming the operator. This well was a dry hole.

We are currently in the 6th and final period of the exploration contract, which expires October 24, 2011. There is an obligation to drill one exploration well in the current exploration period.

In 2010, one exploration well was drilled (Jilguero-1), which resulted in an oil discovery.   In 2011, we plan to drill one exploration well which will satisfy the exploration obligation.

Rio Magdalena
 
The Rio Magdalena Association Contract with Ecopetrol was signed in February 2002. The Rio Magdalena Block covers 72,312 gross 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 and hold a 44% working interest with one partner holding a 56% working interest.  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. According to the terms of the Association Contract, Ecopetrol may back-in for a 30% participation interest to any discoveries on the block upon commercialization.  In 2010 we submitted a proposal to Ecopetrol to relinquish 50% of the area in the block.  Our relinquishment proposal was accepted by Ecopetrol.

 
Page 29 of 113

 

In 2010 one appraisal well was drilled (Popa-3).  The well is currently suspended pending further testing and evaluation. For 2011, there are no capital expenditures planned for Rio Magdalena.

Mecaya
 
The Mecaya Exploration and Exploitation contract was signed June 2006. The Mecaya contract area covers 74,128 gross acres in southern Colombia in the Putumayo Basin. We are the operator and currently have a 15% participation interest and three partners with 27%, 28% and 30% interest. We are in exploration period three of this contract and are obliged to drill one exploration well, and re-enter a previously drilled well. We were contractually obligated to complete this work by June 2009; however, the contract terms have been suspended due to operational difficulties in the area. There are two more exploration periods following, each of which are 12 months in duration. The third period has an obligation to acquire seismic data, and the fourth period has the obligation to drill one exploration well. The exploitation phase for this contract expires 24 years after commerciality is approved for any discovery. The property will be returned to the government upon expiration of the production contract.
 
In 2010, there were no capital expenditures and no capital expenditures are planned for 2011.

Catguas Block

Solana acquired the Catguas Block in November 2005. We are the operator of the block which covers 393,150 gross acres in the Catatumbo Basin.  One partner has a 15% working interest in the southern 70% of the block and a 50% working interest in the remainder of the block. The block is held under an ANH contract.

There are no wells producing on this block. We are in the third period of the exploration portion of the contract, out of a total of six periods. This period expired June 5, 2010, and had an obligation to re-enter an existing well and drill two exploration wells. All remaining periods are 12 months in length and carry a work obligation of one well. The exploitation phase would last 24 years from any declaration of a commercial discovery.

In 2010, there was no exploration activity on this block.  There is no activity planned for 2011 as the block contract is in suspension by ANH as a result of force majeure.
 
Cauca 6 Block

We were awarded the Cauca 6 Block in June 2010 in the Colombia Bid Round 10, pending ANH approval.  The block covers 571,098 gross acres in the Cauca-Patia basin and we hold a 100% working interest.  After the contract is signed, the initial six month phase of community consultation will begin.  The first exploration phase of the contract will require the acquisition of 200 kilometers of 2D seismic and the drilling of one stratigraphic well.

In 2011, we plan to acquire aeromagnetic and aerogravity surveys as well as geological studies.

Cauca 7 Block

We were awarded the Cauca 7 Block in June 2010 in the Colombia Bid Round 10, pending ANH approval.  The block covers 785,452 gross acres in the Cauca-Patia basin and we a hold a 100% working interest. After the contract is signed, the initial six month phase of community consultation will begin.  The first exploration phase of the contract will require the acquisition of 250 kilometers of 2D seismic and the drilling of one stratigraphic well.

In 2011, we plan to acquire aeromagnetic and aerogravity surveys  as well as geological studies.

Putumayo 10 Block

We were awarded the Putumayo 10 Block in June 2010 in the Colombia Bid Round 10, pending ANH approval.  The block covers 114,096 gross acres in the Putumayo basin and we hold a 100% working interest. After the contract is signed, the initial six month phase of community consultation will begin.  The first exploration phase of the contract will require the acquisition of 70 kilometers of 2D seismic and the drilling of two exploration wells.

In 2011, we plan to acquire 100 kilometers of 2D seismic and drill one exploration well.

 
Page 30 of 113

 

Putumayo 1 Block

We acquired a 55% operated interest in the Putumayo-1 Block in 2010.  The block covers 114,881 gross acres in the Putumayo basin. The first phase of this contract expires in September 2012 and requires the acquisition of 159 square kilometers of 3D seismic and the drilling of one exploration well.

In 2011 we plan to acquire 220 square kilometers of 3D seismic.

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 additional properties in Argentina, including the remaining 50% interest in Nacatimbay and Ipaguazu, a 50% interest in El Vinalar, a 100% interest in El Chivil, Surubi and Santa Victoria, and a 93.18% interest in Valle Morado.  In 2009 we relinquished our rights to the Nacatimbay Block and in 2011 we plan to relinquish our interest in the Ipaguazu Block. Our Argentina properties are located in the Noroeste Basin in northern Argentina.

Palmar Largo
 
The Palmar Largo joint venture block encompasses 341,500 gross acres. This asset is comprised of several producing oil fields in the Noroeste Basin. 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.
 
The Palmar Largo Block rights expire in 2017 but provide for a ten-year extension. We do not have any outstanding work commitments. On expiry of the block rights, ownership of the producing assets will revert to the provincial government.

In 2010, only regular field maintenance and workover activities were performed at Palmar Largo.  In 2011, only regular field maintenance and workover activities are planned.
 
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. We are the operator of the block. 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. The Ipaguazu Block covers 21,745 gross acres.  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 April 2010, production operations at the Ipaguazu-1 well were suspended due to low well productivity.  We filed an application for relinquishment of the Ipaguazu Block in 2010 and are awaiting government approval.
 
El Vinalar
 
In June 2006, we acquired a 50% working interest in the El Vinalar Block, which covers 61,035 gross acres.
 
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.

In 2010, we performed regular field maintenance and workovers in El Vinalar.  Only regular field maintenance and workover activities are planned in 2011.

El Chivil

We purchased El Chivil in 2006. We are the operator and hold a 100% working interest in El Chivil which covers 30,393 gross acres. The Chivil field was discovered in 1987. Three wells were drilled with two remaining in production. The contract for this field expires in 2015 with the option for a ten year extension.

In 2010, we performed regular field maintenance and workovers  in El Chivil.  Only regular field maintenance and workover activities are planned in 2011.

Surubi

We purchased the Surubi Block in late 2006. We are the operator of the Surubi Block which covers 90,811 gross acres and have an 85% working interest. In 2008, we drilled the Proa-1 discovery well, which began production in September, 2008. The provincial oil company REFSA farmed-in to the block for a 15% working interest, and is paying its share of well costs from its share of production from Proa-1. The contract for this block expires in 2023 and we have no outstanding commitments related to the block contract.

 
Page 31 of 113

 

In 2010, we performed regular maintenance and workover activities at Proa-1. For 2011, we plan to drill a development well (Proa-2) in addition to performing regular maintenance and workover activities.

Valle Morado

We purchased the Valle Morado Block at the end of 2006.  Valle Morado covers 49,099 gross acres and we are the operator with a 93.2% working interest. The remaining 6.8% interest is held equally by two other companies. The previous owners had the option to back-in for an 18% working interest under certain circumstances; however, we paid out the owners and eliminated this option during 2010. The contract for this block expires in 2034 and we have no outstanding commitments related to the block contract.

Valle Morado GTE.St.VMor-2001 was first drilled in 1989. The original owner subsequently completed a 3D seismic program over the field and constructed a gas plant and pipeline infrastructure. Production began in 1999 from the GTE.St.VMor-2001 and was shut-in in 2001 due to water incursion. In 2008, we successfully re-entered the well.

In July 2010, we commenced a re-entry and sidetrack operation on the GTE.St.VMor-2001 well.  In February 2011, these operations were suspended and the wellbore will be abandoned due to a number of operational challenges encountered.  Gran Tierra Energy continues to review alternatives associated with the field development.

Santa Victoria

We purchased the Santa Victoria Block late in 2006. Santa Victoria covers 1,033,889 gross acres and we are the operator with a 100% working interest. It is an exploration block with no production history. The contract’s exploration period expired in December 2010 however we received a 90 day extension to March 29, 2011. We are using the extension to allow for the interpretation of the 202 square kilometers of 3D seismic acquired in 2010 and determine whether to proceed into the next phase of the contract. We have no other outstanding commitments related to the block contract.

Oil and Gas Properties - Peru

We entered Peru in 2006 through the award by the government of Peru of two frontier exploration blocks, Block 122 and Block 128, in the Maranon Basin.  In September 2010, we acquired a 20% non-operated working interest in three blocks in the Maranon Basin. These three blocks, Block 123, Block 124, and Block 129 are adjacent to Block 122 and Block 128.  In December 2010, we further increased our acreage position in the Maranon Basin in Peru by acquiring a 60% working interest in Block 95.   The acquisition in 2010 of these four blocks is subject to approval by the Government of Peru.

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 is assessed 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%.  This royalty structure applies to all 6 blocks in Peru that we have an interest in.

Block 122 and Block 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 gross acres and Block 128 covers 2,218,389 gross acres. In February 2011, we relinquished 20%, or 443,678 gross acres in Block 128.  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 financial commitment of $3.5 million over the seven years for each block which includes technical studies, seismic acquisition and the drilling of exploration wells. We are currently in the second phase of each of these block’s contracts. In 2010, we received EIA approvals for seismic and drilling operations for these blocks and acquired 260 kilometers of 2D seismic on Block 128.  At year end, the 290 kilometer 2D seismic acquisition was ongoing at Block 122.  Exploration wells are planned for Block 128 (spud February 2011) and for Block 122 in the third quarter of 2011. Up to two more exploration wells are contingent upon the results of these wells.

Block 123, Block 124 and Block 129

In September 2010, we acquired a 20% working interest in Block 123, Block 124, and Block 129, subject to government approval.  These three blocks have a total area of approximately 6.7 million acres and Burlington Resources Peru Limited (a wholly owned subsidiary of ConocoPhillips) is the operator of these blocks.   We are currently in the second phase of each of the contracts which require seismic acquisition totaling 1,400 kilometers for all blocks prior to phase completion. In 2010, 747 kilometers of 2D seismic was acquired on these blocks.  In 2011, we plan to complete the seismic commitments required under phase two for Blocks 123 and Block 129. We may request an extension of phase two in Block 124 to facilitate completion of the seismic commitment for that block.

 
Page 32 of 113

 

Block 95

In December 2010, we acquired a 60% working interest in Block 95, subject to government approval.  Block 95 has a total area of 1.3 million gross acres.  We will be the operator of Block 95. We are currently in phase three of the contract which has been delayed as a result of force majeure. Once force majeure has ended, we plan to apply to extend the current phase to provide sufficient time to complete the well commitment. Block 95 contains a drill ready prospect which we plan to drill in 2011.

Oil and Gas Properties - Brazil

Gran Tierra entered Brazil in 2009 with the opening of a business development office. In August 2010, we acquired a 70% working interest in four exploration blocks in the Reconcavo Basin, subject to government approval.

Blocks REC-T-129, REC-T-142, REC-T-155, and REC-T-224

Blocks REC-T-129, REC-T-142, REC-T-155 and REC-T-224 are located approximately 70 kilometers Northeast of Salvador, Brazil in the prolific Reconcavo Basin. This basin covers an area of approximately 10,000 square kilometers, contains 129 fields, and has produced over 1.5 billion barrels of oil to date (source: IHS Inc., 2010). Production from this basin is mainly light oil ranging between 35 and 40 API. These four blocks have a total area of 27,075 gross acres.  Gran Tierra is awaiting regulatory approval from Brazil’s ANP to recognize Gran Tierra as the operator of these exploration blocks. All of our blocks in Brazil are subject to an 11% royalty, which consists of a 10% crown royalty and a 1% landowner royalty which applies to onshore blocks. All four blocks are in phase one of the contracts which expire March 12, 2011. An application for a six month extension has been made for Blocks REC-T-129, REC-T-142, and REC-T-224. The first phase for each of Blocks REC-T-129 and REC-T-142 requires the drilling of an exploratory well and, for Block REC-T-224,14 requires the acquisition of 35 square kilometers of 3D seismic. There is no remaining phase one commitment for Block REC-T-155.

In the third and fourth quarters of 2010, 93 square kilometers of 3D seismic was acquired over Blocks REC-T-129, REC-T-142 and REC-T-155.  An additional 35 square kilometers of 3D seismic survey is planned for the first quarter of 2011 for Block REC-T-224. The 1-ALV-2-BA well on Block REC T-155 is presently producing approximately 500 BOPD gross (350 BOPD net after royalties). We plan to dual complete this well in the first quarter of 2011 and plan to drill two appraisal wells to further develop this discovery. In 2011, we plan to drill four exploration wells on Blocks REC-T-129, REC-T-142 and REC-T-155. The drilling of these wells meets or exceeds each blocks’ phase one commitments. Blocks REC-T-129, REC-T-142, and REC-T-224 will require an additional exploration well to satisfy the phase two commitments and these are planned for 2012.  In January 2011, Gran Tierra opened an office in Salvador, Brazil to manage the field operations for the Reconcavo Basin blocks.

Reserves
 
No estimates of 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, GLJ Petroleum Consultants Ltd., at least annually. The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. Therefore the accuracy of the reserve estimate is dependent on the quality of the data, the accuracy of the assumptions based on the data, and the interpretations and judgment related to the data.

The policies we have developed are applied company wide, and are comprehensive in nature. The result of the policies is SEC compliant reserve estimates and disclosures. The policy is applied by all staff involved in generating and reporting reserve estimates including geological, engineering and finance personnel. Calculations and data are reviewed at multiple levels of the organization to ensure consistent and appropriate standards and procedures.

The primary internal technical person in charge of overseeing the preparation of our reserve estimates is the Manager of Reservoir Engineering. He has a bachelor’s degree of science in petroleum engineering and is a professional engineer and member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta. He is currently responsible for our engineering activities including reserves reporting, asset evaluation, field development and monitoring production operations. He has over 30 years of industry experience in various domestic and international engineering and management roles.

 
Page 33 of 113

 

The technical person responsible for overseeing the reserves evaluation is Vice President, International of GLJ Petroleum Consultants Ltd.  He has a Bachelor of Science Degree in Engineering Physics and is a registered professional engineer in the Province of Alberta.  He has over 20 years of industry experience in various domestic and international engineering and management roles.
 
The SEC definitions related to oil and natural gas reserves, per Regulation S-X, reflecting our use of deterministic reserve estimation methods, are as follows:

 
Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 
(i)
The area of the reservoir considered as proved includes:
 
A.
The area identified by drilling and limited by fluid contacts, if any, and
 
B.
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
A.
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and.
 
B.
The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
 
Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of section 210.4-10(a) of Regulations S-X.

 
Page 34 of 113

 

 
Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 
(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
 
(vi)
Pursuant to paragraph (a)(22)(iii) of section 210.4-10(a) of Regulations S-X, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 
Reasonable Certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant that to decrease.

 
Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

 
Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
 
Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of section 201.4-10(a) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.

 
Page 35 of 113

 

The following table sets forth our oil reserves net of all royalties as of December 31, 2010 (all quantities in thousands of barrels of oil, “mbbls”, or millions of cubic feet of natural gas, “Mmcf”). Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, as they are in our case, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. 
 
   
Reserves
 
   
Liquids*
   
Natural Gas
 
Reserves Category
 
mbbls
   
Mmcf
 
PROVED
           
Developed:
           
Colombia
    18,528       1,232  
Argentina
    940       -  
Undeveloped
               
Colombia
    3957       -  
Argentina
    173       -  
TOTAL PROVED
    23,598       1,232  
PROBABLE
               
Developed
               
Colombia
    4,060       147  
Argentina
    534       -  
Undeveloped
               
Colombia
    2,790       -  
Argentina
    35       -  
TOTAL PROBABLE
    7,419       147  
POSSIBLE
               
Developed
               
Colombia
    5,851       181  
Argentina
    427       -  
Undeveloped
               
Colombia
    8,371       -  
Argentina
    1,657       41,880  
TOTAL POSSIBLE
    16,306       42,061  

*Liquids include oil and Natural Gas Liquids.  We have Natural Gas Liquids reserves in small amounts in Argentina only.  Colombia Liquids reserves are 100% oil.

Proved Undeveloped Reserves

In Colombia, our proved undeveloped reserves increased to 4.0 million barrels (“Mmbbls”) at December 31, 2010 from 0.6 Mmbbls at December 31, 2009. Approximately 70% of these proved undeveloped reserves are located in our Costayaco field, under development in 2011. Approximately 30% of the proved undeveloped reserves are located in our Moqueta discovery, which will be developed in 2011. Our proved undeveloped reserves in Argentina decreased slightly from 211,000 barrels at December 31, 2009 to 173,000 barrels at December 31, 2010 due to a revision to forecast development activity. We expect to develop these reserves in 2011.

 
Page 36 of 113

 
 
Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario
 
   
Proved Reserves
   
Probable Reserves
     
Possible Reserves
 
   
Liquids
   
Natural Gas
   
Liquids
    Natural Gas     Liquids    
Natural Gas
 
Price Case
 
(mbbls)
   
(Mmcf)
   
(mbbls)
    (Mmcf)     (mbbls)    
(Mmcf)
 
WTI +10%
                                       
Colombia
    22,185       1,232       6,670       148       14,113       180  
Argentina
    1,113       -       569       -       2,083       41,880  
Total
    23,298       1,232       7,239       148       16,196       42,060  
WTI – 10%
                                               
Colombia
    22,709       1,232       6,889       148       14,472       180  
Argentina
    1,113       -       569       -       2,083       41,880  
Total (1)
    23,822       1,232       7,458       148       16,555       42,060  
(1)  The total proved Liquids is higher as a result of a 10% decrease in WTI as compared to a 10% increase in WTI.  The lower price results in reduced additional government and third party royalties paid, increasing the net after royalty volumes.

The price cases presented involve changes to the WTI price – one with a 10% increase, the second with a 10% decrease. Natural gas prices are not affected by WTI, therefore the volumes of natural gas reserves do not change. Additionally, the oil price in Argentina is set by the government as described in Item “1 Business” under the caption “Markets and Customers”. The price in Argentina is not sensitive to changes in the WTI price, therefore the price scenarios considered do not result in changes to oil and natural gas reserves for Argentina. Cost schedules were held constant for the two price cases.
 
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, 2010 is set forth in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the Unaudited Supplementary Data provided following our Financial Statements in Item 8. We prepared the estimate of standardized measure of proved reserves in accordance with the Financial Accounting Standards Board (“FASB”) ASC 932, “Extractive Activities – Oil and Gas”.
 
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, 2010.
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Colombia
                                   
     Exploration
                                   
          Productive
    4.00       3.50       -       -       1.00       0.40  
          Dry
    1.00       1.00       2.00       0.70       1.00       0.40  
          In Progress
    3.00       2.43       1.00       1.00       -       -  
     Development
                                               
          Productive
    2.00       1.70       3.00       3.00       3.00       1.50  
          Dry
    -       -       1.00       1.00       -       -  
          In Progress
    2.00       2.00       1.00       0.70       1.00       1.00  
Total Colombia
    12.00       10.63       8.00       6.40       6.00       3.30  
Argentina
                                               
     Exploration
                                               
          Productive
    -       -       -       -       1.00       0.85  
          Dry
    -       -       -       -       -       -  
          In Progress
    1.00       0.93       -       -       -       -  
     Development
                                               
          Productive
    -       -       -       -       -       -  
          Dry
    -       -       -       -                  
          In Progress
    -       -       -       -       -       -  
Total Argentina
    1.00       0.93       -       -       1.00       0.85  
Peru
                                               
     Exploration
                                               
          Productive
    -       -       -       -       -       -  
          Dry
    -       -       -       -       -       -  
          In Progress
    -       -       -       -       -       -  
     Development
                                               
          Productive
    -       -       -       -       -       -  
          Dry
    -       -       -       -       -       -  
          In Progress
    -       -       -       -       -       -  
Total Peru
    -       -       -       -       -       -  
Total
    13.00       11.56       8.00       6.40       7.00       4.15  

 
Page 37 of 113

 
 
Following are the results as of February 18, 2011 of wells in progress at December 31, 2010:

   
Productive
   
Dry
   
Still in Progress
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Colombia
    -       -       -       -       5.00       4.43  
Argentina
    -       -       1.00       0.93       -       -  
Peru
    -       -       -       -       -       -  
Total
    -       -       1.00       0.93       5.00       4.43  

Well Statistics

The following table sets forth our producing wells as of December 31, 2010.

   
Oil Wells (1)
   
Gas Wells
   
Total Wells
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Colombia
    26.00       15.70       1.00       0.42       27.00       16.12  
Argentina
    32.00       8.35       -       -       32.00       8.35  
Peru
    -       -       -       -       -       -  
Total
    58.00       24.05       1.00       0.42       59.00       24.47  
 (1) Includes 2.0 gross and net water injector wells in Colombia and 12.0 gross and 1.68 net water injector wells in Argentina.

Developed and Undeveloped Acreage
 
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2010.

   
Developed
   
Undeveloped (1)
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Colombia
    230,310       163,929       936,961       654,594       1,167,271       818,523  
Argentina
    572,839       238,472       1,055,634       1,055,634       1,628,473       1,294,106  
Peru
    -       -       3,436,040       3,436,040       3,436,040       3,436,040  
Brazil
    -       -       -       -       -       -  
Total
    803,149       402,401       5,428,635       5,146,268       6,231,784       5,548,669  
 
(1)  Not included in undeveloped acreage is land acquired through agreements for which government approval is pending.  This undeveloped land includes 1,470,645 gross and net acres in Colombia, 7,995,101 gross (5,544,820 net) in Peru, and 27,076 gross (18,953 net) acres in Brazil.  Additionally, the undeveloped land acreage for Argentina includes 21,745 gross and net acres in the Ipaguazu Block for which application for relinquishment has been filed and we are awaiting government approval and 443,678 gross and net acres in Block 128 in Peru, which was relinquished in February 2011.

 
Page 38 of 113

 

Our net developed acreage in Colombia includes acreage in the Santana Block (less than 1%); the Magangue Block (1%); the Guayuyaco Block (4%); the Garibay Block (5%); and the Chaza Block (10%).  Our net undeveloped acreage in Colombia, not including acreage acquired through agreements still subject to government approval, is in the Putumayo 10, Cauca 6 and Cauca 7 blocks (less than 1% each); the Mecaya Block (1%); the Azar Block (2%); the Rio Magdalena Block (4%); the Catguas A Block (7%); the Putumayo 1 Block (8%); the Piedemonte Sur Block (9%); the Piedemonte Norte and Rumiyaco blocks (10% each); and the Catgua B Block (29%).

In Argentina, our net developed acreage includes acreage in the El Chivil Block (2.3%); the El Vinalar Block (2.4%); the Valle Morado Block (3.5%); the Palmar Largo Block (20%); and the Surubi Block (6.5%).  Our net undeveloped acreage in Argentina is in the Santa Victoria Block (98%) the Ipaguazu Block (2%), which currently has an application to relinquish filed with the government.
 
In Peru, our net undeveloped acreage, not including that acquired through agreements for which government approval is pending or that which was relinquished after year-end,  includes acreage in Block 122 (35%) and Block 128 (65%).

In Brazil all our net undeveloped acreage was acquired in an agreement still pending government approval.

Item 3.  Legal Proceedings 

Ecopetrol and Gran Tierra Colombia, the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the procedure for allocation of oil produced and sold during the long term test of the Guayuyaco-1 and Guayuyaco-2 wells. There is a material difference in the interpretation of the procedure established in Clause 3.5 of Attachment-B of the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for benefit of Ecopetrol. There has been no agreement between the parties, and Ecopetrol has filed a lawsuit in the Contravention Administrative Court in the District of Cauca regarding this matter. Gran Tierra Colombia filed a response on April 29, 2008 in which it refuted all of Ecopetrol’s claims and requested a change of venue to the courts in Bogota.  Closing arguments were presented by all parties during 2009.  We are awaiting the Court’s decision.  At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $5.5 million.

We have several other lawsuits and claims pending for which we currently cannot determine the ultimate result. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our consolidated financial position or results of operations.

Item 4.  Removed and reserved

End of Item 4

Executive Officers of the Registrant

Set forth below is information regarding our executive officers as of February 18, 2011.

Name
 
Age
 
Position
Dana Coffield  
 
52
 
President and Chief Executive Officer; Director
Martin H. Eden  
 
63
 
Chief Financial Officer
Shane O’Leary
 
54
 
Chief Operating Officer
David Hardy
 
56
 
General Counsel, Vice-President Legal, and Secretary
Rafael Orunesu
 
55
 
President and General Manager Gran Tierra Energy Argentina
Julian Garcia
 
52
 
President and General Manager Gran Tierra Energy Colombia
Julio Cesar Moreira
 
49
 
President and General Manager Gran Tierra Energy Brasil
 
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, at the time North America’s largest independent oil and gas company, from 2003 to 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 exploration operations 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 million barrels of oil equivalent reserves.      

 
Page 39 of 113

 

Mr. Coffield graduated from the University of South Carolina with a Masters of Science (MSc) 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 extensive experience in accounting, finance and administration in the petroleum industry in Canada and overseas. During his career his responsibilities have included management of all finance related activities of Canadian oil and gas exploration and production companies operating in Canada, Africa and Central Asia. 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 the Chief Financial Officer of Chariot Energy Inc., a Canadian private oil and gas company. From January 2004 to September 2004, he was the Chief Financial Officer of Assure Energy Inc., a publicly traded oil and gas company listed in the United States. From January 2001 to December 2002, he was Chief Financial Officer of Geodyne Energy Inc., a publicly listed Canadian oil and gas company. From 1997 to 2000, he was Controller and subsequently Chief Financial Officer 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. He is currently a director of Touchstone Oil and Gas Ltd., a private company. 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.
 
Shane P. O’Leary, Chief Operating Officer. Mr. O’Leary joined the company as Chief Operating Officer effective March 2, 2009. Mr. O’Leary’s regional experience includes South America, North Africa, the Middle East, the former Soviet Union, and North America. Prior to joining Gran Tierra, Mr. O’Leary was President and Chief Executive Officer of First Calgary Petroleums Ltd., an oil and natural gas company actively engaged in exploration and development activities in Algeria. In this role, he was responsible for all operating and corporate activities involved in a $2 billion development program for the exploitation of a resource base exceeding 3 Trillion Cubic Feet of natural gas equivalent in the Sahara desert, Algeria. Mr. O'Leary led initiatives to explore strategic options which resulted in the sale of the company to ENI SpA for over $1 billion. From 2002 to 2006, Mr. O’Leary worked for Encana Corporation where his positions included Vice President of Development Planning and Engineering, International New Ventures, as well as Vice President Brazil Business Unit. In these roles Mr. O'Leary was responsible for all engineering and development planning for new discoveries of the International New Ventures Division and later leading the Brazil team involved in appraising an offshore discovery subsequently divested for $360 million. Mr. O'Leary was also architect of a technology cooperation agreement with Petrobras involving numerous partnerships in offshore acreage in exchange for assistance to Petrobras in applying Canadian Heavy Oil production technology in Brazil. From 1985 to 2002 he worked for the Amoco Production Company/BP Exploration where he occupied numerous senior finance, planning, and business development positions with assignments in Canada, U.S.A., Azerbaijan and Egypt, culminating in his role as Business Development Manager for BP Alaska Gas. Early in his career Mr. O’Leary worked as a Corporate Banking Officer for Bank of Montreal’s Petroleum group in Calgary, a Reservoir Engineer for Dome Petroleum, and as a Senior Field Engineer for Schlumberger Overseas, S.A. in Kuwait. Mr. O’Leary earned his Bachelor of Science degree in chemical engineering from Queen’s University in Kingston, Ontario and his Masters in Business Administration from the University of Western Ontario in London, Ontario. He is a member of the Canadian National Committee of the World Petroleum Council and The Association of Professional Engineers, Geologists, and Geophysicists of Alberta (P. Eng).

David Hardy, General Counsel, Vice President Legal and Secretary. Mr. Hardy joined Gran Tierra as General Counsel, Vice President Legal and Secretary on March 1, 2010. He has more than 20 years experience in the legal profession. Before joining Gran Tierra, he worked for Encana Corporation from 2000 through 2009 where he held various positions, including: Vice President Divisional Legal Services, Integrated Oil and Canadian Plains Divisions; Vice President Regulatory Services, Corporate Relations Division; and Associate General Counsel, Offshore and International Division. For 4 of his 8 years in the Offshore and International Division of Encana, Mr. Hardy led the Legal and Commercial Negotiations Group. He has experience in new ventures activities and operations involving projects in various countries, including Australia, Brazil, Chad, Libya, Oman, Qatar and Yemen. Prior to joining Encana, Mr. Hardy spent over 10 years in private practice and was a partner in a law firm in Calgary, Alberta. He holds a Bachelor of Laws Degree from the University of Calgary and is a member of the Law Society of Alberta and the Association of International Petroleum Negotiators.

Rafael Orunesu, President and General Manager Gran Tierra Argentina. Mr. Orunesu joined Gran Tierra in March 2005. He brings a mix of operations management, project evaluation, production geology, reservoir and production engineering 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 million 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.

 
Page 40 of 113

 
 
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.

Julian Garcia, President and General Manager Gran Tierra Energy Colombia. Mr. Garcia joined our company as President and General Manager Gran Tierra Energy Colombia in December 2009. Mr. Garcia has more than 25 years of petroleum industry experience in Colombia and internationally. He has extensive experience in all aspects of the petroleum industry, including exploration and production operations, commercial, finance, project management and strategic leadership. He has held a range of progressively senior positions, technical and financial, at companies including Ecopetrol, BP, and the National Hydrocarbon Agency, where he was Technical Director. Most recently, Mr. Garcia was General Manager for Emerald Energy Plc Colombia, where the company grew reserves 10-fold in less than five years; he was responsible for all operations and businesses in Colombia and Peru with 11 blocks in 6 basins. Mr. Garcia holds a Bachelors of Civil Engineering and a Masters in Economics from Universidad de Los Andes, a Masters in Civil Engineering from Colorado State University USA, and a Masters of Business Administration from the University of Birmingham, UK.

Julio Cesar Moreira, President Gran Tierra Energy Brasil. Mr. Moreira joined our company as President, Gran Tierra Brazil in September 2009. Mr. Moreira has over 25 years of experience working for international companies in Brazil and USA in senior business development and management positions. Most recently, he was Managing Director for IBV Brasil Petroleo Ltda from September 2008 to August 2009 where he managed a portfolio of assets including 10 Exploration Deep Water Blocks located in Sergipe-Alagoas, Espirito Santo, Potiguar and Campos Basins, all in Brazil, and Brazil Country Manager for Encana Corporation from December 2001 to September 2008, where he was instrumental in capturing assets which were later sold for a combined value of over $500 million. Before Encana Corporation, Mr. Moreira was Brazil New Ventures & Business Development Vice President for Unocal Corporation where he successfully completed a $180MM corporate transaction to acquire a Natural Gas / Condensate field in Northeast Brazil and captured Deep Water Exploration assets offshore Brazil. Mr. Moreira holds an Information Technology degree from Universidade Federal Fluminense in Rio de Janeiro, and a post-graduate degree in Marketing from Rio Catholic University. In addition, he attended the Executive MBA Program at UFRJ/Coppead (Brazil), the Executive Management programs in Oil and Gas at Thunderbird (USA) and the Ivey Executive Program at the University of Western Ontario (Canada).

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

Our common stock trades on the NYSE,Amex, and on the TSX under the symbol “GTE”. In addition, the exchangeable shares in one of our subsidiaries, Gran Tierra Exchangeco, are listed on the TSX and are trading under the symbol “GTX”.

As of February 18, 2011 there were approximately: 51 holders of record of shares of our common stock and 240,857,632 shares outstanding with $0.001 par value; and one share of Special A Voting Stock, $0.001 par value representing approximately 9 holders of record of 7,811,112 exchangeable shares which may be exchanged on a 1-for-1 basis into shares of our Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 10 holders of record of 9,539,042 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into shares of our common stock.
 
For the quarters indicated from January 1, 2009 through the end of the fourth quarter of 2010, the following table shows the high and low closing sale prices per share of our common stock as reported on the NYSE Amex.
 
   
High
   
Low
 
Fourth Quarter 2010
 
$
8.39
   
$
7.23
 
Third Quarter 2010
 
$
7.72
   
$
5.06
 
Second Quarter 2010
 
$
6.64
   
$
4.70
 
First Quarter 2010
 
$
6.08
   
$
4.68
 
Fourth Quarter 2009
 
$
6.00
   
$
3.99
 
Third Quarter 2009
 
$
4.26
   
$
2.92
 
Second Quarter 2009
 
$
3.51
   
$
2.31
 
First Quarter 2009
 
$
3.50
   
$
2.06
 
 
Dividend Policy
 
We have never declared or paid dividends on the shares of common stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future. Payment of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including current financial condition, operating results and current and anticipated cash needs. Under the terms of our credit facility we cannot pay any dividends if we are in default under the facility, and if we are not in default then are required to obtain bank approval for any dividend payments made by us exceeding $2 million in any fiscal year.

 
Page 41 of 113

 

Unregistered Sales of Equity Securities
 
On 16 separate dates beginning on October 1, 2010 and ending on December 31, 2010, we sold an aggregate of 689,054 shares of our common stock for an aggregate purchase price of $764,582. These shares were issued to 29 holders of warrants to purchase shares of our common stock upon exercise of the warrants. The shares were issued to these holders in reliance on Section 4(2) under the Securities Act, in that they were issued to the purchasers of the warrants, who had represented that they were accredited investors as defined in Regulation D under the Securities Act. On October 14, 2010 we issued 158,730 shares of our common stock to one holder of exchangeable shares, which were issued by a subsidiary of Gran Tierra in a share exchange on November 10, 2005. The shares were issued to this holder in reliance on Regulation S promulgated by the SEC as the investor was not a resident of the United States.

Performance Graph


      12/05       12/06       12/07       12/08       12/09       12/10  
                                                 
Gran Tierra Energy Inc
    100       43.12       94.93       101.45       207.61       291.67  
Russell Small Cap Completeness
    100       114.89       120.46       73.51       101.22       128.18  
Dow Jones US Exploration & Production TSM
    100       105.08       147.43       86.94       123.04       145.68  

The Dow Jones US Exploration and Production TSM was previously named the DJ Wilshire Exploration and Production.

 
Page 42 of 113

 

Item 6. Selected Financial Data

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

   
Year Ended
December 31,
   
Year Ended
December 31,
   
Year Ended
December 31,
   
Year Ended
December 31,
   
Year Ended
December 31,
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
Statement of Operations Data
                             
Revenues and other income
                             
Oil and natural gas sales
  $ 373,286     $ 262,629     $ 112,805     $ 31,853     $ 11,721  
Interest
    1,174       1,087       1,224       425       352  
Total revenues and other income
    374,460       263,716       114,029       32,278       12,073  
Expenses
                                       
Operating
    59,446       40,784       19,218       10,474       4,233  
Depletion, depreciation, accretion  and impairment
    163,573       135,863       25,737       9,415       4,088  
General and administrative
    40,241       28,787       18,593       10,232       6,999  
Liquidated damages
    -       -       -       7,367       1,528  
Derivative financial instruments  (gain) loss
    (44 )     190       (193 )     3,040       -  
Foreign exchange (gain) loss
    16,838       19,797       6,235       (78 )     371  
Total expenses
    280,054       225,421       69,590       40,450       17,219  
                                         
Income (loss) before income taxes
    94,406       38,295       44,439       (8,172 )     (5,146 )
Income tax expense
    (57,234 )     (24,354 )     (20,944 )     (295 )     (678 )
                                         
Net income (loss)
  $ 37,172     $ 13,941     $ 23,495     $ (8,467 )   $ (5,824 )
                                         
Net income (loss) per  common share — basic
  $ 0.15     $ 0.06     $ 0.19     $ (0.09 )   $ (0.08 )
Net income (loss) per  common share — diluted
  $ 0.14     $ 0.05     $ 0.16     $ (0.09 )   $ (0.08 )

   
As at
December 31,
   
As at
December 31,
   
As at
December 31,
   
As at
December 31,
   
As at
December 31,
 
Balance Sheet Data
 
2010
   
2009
   
2008
   
2007
   
2006
 
                               
Cash and cash equivalents
  $ 355,428     $ 270,786     $ 176,754     $ 18,189     $ 24,101  
Working capital (including cash)
    265,835       215,161       132,807       8,058       14,541  
Oil and gas properties
    721,157       709,568       765,050       63,202       56,093  
Deferred tax asset - long term
    -       7,218       10,131       1,839       444  
Total assets
    1,249,254       1,143,808       1,072,625       112,797       105,537  
Deferred tax liability and  deferred remittance tax - long term
    205,606       217,528       214,210       10,567       9,876  
Other long-term liabilities
    4,469       4,258       4,251       1,986       634  
Shareholders’ equity
  $ 886,866     $ 816,426     $ 791,926     $ 76,792     $ 76,195  

 
Page 43 of 113

 
 
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 Argosy Energy International L.P.’s assets in Colombia 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. In November 2008, we acquired Solana for $671.8 million through the issuance to Solana stockholders of either shares of our common stock or shares of common stock of a subsidiary of Gran Tierra.

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

This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of Part I of this Annual Report on Form 10-K regarding the identification and risks relating to forward-looking statements, as well as Part I, Item 1A “Risk Factors” in this Annual Report on Form 10-K.

The following discussion of our financial condition and results of operations should be read in conjunction with the Financial Statements and Supplementary Data as set out in Part II – Item 8 of this Annual Report on Form 10-K.

Overview

We are an independent international energy company incorporated in the United States and engaged in oil and natural gas acquisition, exploration, development and production. We are headquartered in Calgary, Alberta, Canada and operate in South America in Colombia, Argentina, Peru, and Brazil.

In September 2005, we acquired our initial oil and gas interests and properties, which were in Argentina. During 2006, we increased our oil and gas interests and property base through further acquisitions in Colombia, Argentina 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 June 2006.

In 2007, we made a new field discovery, Costayaco, in the Chaza Block of the Putumayo Basin in Colombia.

Effective November 14, 2008, we completed the acquisition of Solana Resources Limited (“Solana”), an international resource company engaged in the acquisition, exploration, development and production of oil and natural gas in Colombia and incorporated in Alberta, Canada. At the date of acquisition, Solana held various working interests in nine blocks in Colombia including a 50% working interest in the Chaza Block, which includes the Costayaco field, and a 35% working interest in the Guayuyaco Block, which includes the Juanambu field.

During the third quarter of 2009, we opened a business development office in Rio de Janeiro, Brazil.

In June 2010, we expanded our land position in the Putumayo Basin and added new frontier exploration acreage in Colombia through successful bids on three blocks in Colombia. In August and October 2010 respectively, we made new Colombian field discoveries in Moqueta in the Chaza Block (Putumayo Basin) and Jilguero in the Garibay Block. Also in August 2010, we finalized a farm-in agreement with Alvorada Petroleo S.A. relating to the on-shore Reconcavo Basin in Brazil, pending regulatory approval from Brazil’s Agencia nacional de Petroleo Gas natural e Bioncombustiveis (“ANP”). In Peru in September 2010, we acquired a 20% working interest in three blocks and, in December 2010, we acquired a 60% interest in one block. Both transactions in Peru are subject to government approval.

On January 17, 2011, we announced that we had entered into an Arrangement Agreement to acquire Petrolifera Petroleum Ltd. (“Petrolifera”). Petrolifera is a Canadian based international oil and gas company listed on the Toronto Stock Exchange which owns working interests in 11 exploration and production blocks; three located in Colombia, three in Peru and five in Argentina. The Arrangement Agreement is subject to Petrolifera shareholder and regulatory, stock exchange and court approvals, and is expected to close in March 2011. See “Subsequent Events” below for further details of this transaction.

Business Strategy

Our plan is to continue to build an international oil and gas company through acquisition and exploitation of under-developed prospective oil and gas assets, and to develop these assets with exploration and development drilling to grow commercial reserves and production. Our initial focus is in select countries in South America, currently Colombia, Argentina, Peru, and Brazil; we will consider other regions for future growth should those regions make strategic and commercial sense in creating additional value.
 
We have applied a two-stage approach to growth, initially establishing a base of production, development and exploration assets by selective acquisitions, and secondly achieving additional reserve and production growth through drilling. We intend to duplicate this business model in other areas as opportunities arise. We pursue opportunities in countries with proven petroleum systems; attractive royalty, taxation and other fiscal terms; and stable legal systems.

 
Page 44 of 113

 

Financial and Operational Highlights
   
Year Ended December 31,
 
   
2010
   
% Change
   
2009
   
% Change
   
2008
 
                               
Estimated Proved Oil and Gas Reserves, net of royalties - Millions of Barrels of Oil Equivalent (1) (“Mmboe”) at year end
    23.8       6       22.4       15       19.4  
                                         
Production - Barrels of Oil Equivalent (“boe”) per Day
    14,448       14       12,684       249       3,635  
                                         
Prices Realized - per boe
  $ 70.79       25     $ 56.73       (33 )   $ 84.78  
                                         
Revenue and Other Income ($000s)
  $ 374,460       42     $ 263,716       131     $ 114,029