Item 1. Business
General
Gran Tierra Energy Inc. together with its subsidiaries (“Gran Tierra”) is an independent international energy company engaged in oil and gas exploration, development and production. We own oil and gas properties in Colombia, Argentina and Peru. 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 (US) dollars, unless otherwise indicated.
On November 10, 2005, Goldstrike, Inc., a Nevada corporation (“Goldstrike”), Gran Tierra Energy Inc., a privately-held Alberta, Canada corporation formed in early 2005 which we refer to as “Gran Tierra Canada” and the holders of Gran Tierra Canada’s capital stock entered into a series of transactions pursuant to which Gran Tierra Canada became a wholly-owned subsidiary of Goldstrike. Immediately following the transactions Goldstrike changed its name to Gran Tierra Energy Inc. and continued operations with the management and business operations of Gran Tierra Canada, but remaining incorporated in the State of Nevada. Goldstrike was incorporated in the United States on June 6, 2003. Prior to the transactions described above, Goldstrike was engaged in mineral exploration in British Columbia, Canada.
In the transactions between Goldstrike and the holders of Gran Tierra Canada common stock, Gran Tierra Canada shareholders received, for their shares of Gran Tierra Canada’s common stock: (a) exchangeable shares of a subsidiary of Goldstrike, or (b) shares of Goldstrike common stock, or (c) a combination of exchangeable shares and Goldstrike common stock. Each exchangeable share is exchangeable into one share of our common stock and has the same voting rights as a share of our common stock.
The share exchange between the former shareholders of Gran Tierra Canada and the former Goldstrike was treated as a recapitalization of Gran Tierra for financial accounting purposes. Accordingly, the historical financial statements of Goldstrike before the share purchase and assignment transactions were replaced with the historical financial statements of Gran Tierra Canada before the share exchange in all subsequent filings with the SEC.
On November 14, 2008, Gran Tierra completed the acquisition of all of the outstanding common stock of Solana Resources Limited ("Solana") pursuant to a plan of arrangement (the "Arrangement") under the Business Corporations Act (Alberta) (the "ABCA").
Solana is an international resource company engaged in the acquisition, exploration, development and production of oil and natural gas. Solana was incorporated under the ABCA with its head office in Calgary, Alberta, Canada. Solana's exploration and development properties are located in Colombia and are held through its wholly owned subsidiary, Solana Petroleum Exploration (Colombia) Limited. Solana holds various working interests in nine blocks in Colombia and is the operator in respect of six of those blocks. Four of the nine blocks contain producing assets. Gran Tierra is the operator of two of the producing blocks, Guayuyaco and Chaza, along with one producing well, Inchiyaco, on our Santana block in which Solana is a partner.
Prior to the completion of the Arrangement, Solana was a reporting issuer in Alberta, British Columbia and Ontario (collectively, the "Reporting Jurisdictions") and the Solana common stock traded on the TSX Venture Exchange ("TSX-V") and the Alternative Investment Market of the London Stock Exchange ("AIM"). Following the completion of the Arrangement, the Solana common stock was delisted from trading on the TSX-V and cancelled from AIM. Solana subsequently ceased to be a reporting issuer in the Reporting Jurisdictions.
In the transaction between Gran Tierra and Solana, Solana shareholders received for their shares of Solana’s common stock: (a) exchangeable shares of Gran Tierra Exchangeco, Inc. which shares trade on the Toronto Stock Exchange (TSX), or (b) shares of Gran Tierra common stock, or (c) a combination of exchangeable shares and Gran Tierra common stock. Gran Tierra Exchangeco, Inc. is a wholly-owned subsidiary of Gran Tierra, and each exchangeable share is exchangeable into one share of our common stock and has the same voting rights as a share of our common stock. For a further discussion of the acquisition of Solana, please see the information appearing under the caption “Business Combination” in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
Our principal executive offices are located at 300, 611-10th 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 http://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 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 refers to the total number of wells or acres in which we own a working interest. Net oil and natural gas wells or acres is 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 such oil and natural gas. A working interest owner that owns a portion of the working interest may participate either as operator or by voting his/her percentage interest to approve or disapprove the appointment of an operator and the drilling and other major activities in connection with the development of a property.
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.
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 either exploration or development. An exploration well is a well drilled in search of a previously undiscovered oil-bearing reservoir. A development well is a well drilled to develop an oil-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.
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.
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 our acquisition of Solana. As a result of these acquisitions we hold as of December 31, 2008:
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1,996,575 gross acres in Colombia (1,499,824 net) covering fourteen Exploration and Production contracts and two Technical Evaluation Areas (“TEA”s), five of which are producing and all but one are operated by Gran Tierra;
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1,635,491 gross acres (1,298,658 net) in Argentina covering eight Exploration and Production contracts, four of which are producing, and all but one are operated by Gran Tierra; and
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3,436,040 acres in Peru owned 100% by Gran Tierra, which constitute frontier exploration, in two Exploration and Production contracts operated by Gran Tierra.
Colombia
Putumayo Basin Pipeline Infrastructure
In Colombia in 2008, on the Chaza Block, we completed drilling the Costayaco-2 development well and drilled four more development wells on our Costayaco field, wells Costayaco-3 through -6, and performed a workover on Costayaco-2. We performed two workovers on our 2007 discovery well at Juanambu on the Guayuyaco block, which contributed incremental production. On our Rio Magdalena block we drilled a successful exploration well - Popa-2 which encountered natural gas and natural gas liquids. On our Azar block we re-entered a previously drilled well named Palmera-1, and that well tested a small amount of production. In November 2008, we drilled one dry hole on our Guachiria Norte block. On our Santana block we completed a workover of one well. We also improved our facilities and infrastructure through completing pipelines to connect our discoveries at Juanambu and Costayaco to our existing pipeline infrastructure and performed other ongoing maintenance projects. 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 S.A. (“Ecopetrol”), the Colombian National Oil Company, due to a general strike in the region. On January 12, 2009, crude oil transportation resumed in southern Colombia as a result of the lifting of the strike at the Orito facilities operated by Ecopetrol.
Plans for 2009 in Colombia continue to focus on the development of the Costayaco field. We also plan to drill exploration wells, perform workovers, acquire seismic and perform numerous projects to upgrade facilities. Details of our 2009 plans are contained in Item 2 “Properties.”
Argentina
Gran Tierra lands highlighted in yellow. Other licenses in grey. Green dots are producing oil fields, red dots are producing gas/condensate fields.
In Argentina in 2008, we successfully drilled the exploration well Proa-1 on our Surubi block, which is now producing. We completed several workovers, including nine on the Palmar Largo block, two on the El Vinalar block and one on the El Chivil block, all of which added incremental production. One unsuccessful workover was performed on our Nacatimbay block. We successfully re-entered one well on our Ipaguazu Block and also successfully re-entered one well on our Valle Morado Block.
Details of our 2009 plans are contained in Item 2 “Properties.”
Peru
Gran Tierra lands highlighted in yellow. Other licenses in grey. Green dots are producing oil fields
In Peru in 2008, we completed the acquisition of technical data in the aeromagnetic and aerogravity survey we began in 2007, and also commenced Environmental Impact Assessments (“EIAs”) over blocks 122 and 128. In 2009, we plan to complete the EIAs, conduct drilling feasibility and geological studies and commence acquisition of seismic data over both blocks.
Revenues, profit (loss) and total assets
Our revenues and profit (loss) for each of the last three years, and our total assets as of December 31, 2008, and 2007, are set forth in Item 8 “Financial Statements and Supplementary Data”, which information is incorporated by reference here. Our total assets as of December 31, 2006, were $105.5 million.
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, and Peru; other regions will be considered 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 future 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. In the petroleum industry, geologic settings with proven petroleum source rocks, migration pathways, reservoir rocks and traps are referred to as petroleum 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:
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Position in countries that are welcoming to foreign investment, that provide attractive fiscal terms, stable legal systems and offer opportunities that we believe have been previously ignored or undervalued;
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Build a balanced portfolio of production, development and exploration assets and opportunities;
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Retain operatorship of assets whenever possible to retain control of work programs, budgets, prospect generation, drilling operations and development activities;
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Engage qualified, experienced and motivated professionals;
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Establish an effective local presence, with strong constructive relationships with host governments, ministries, agencies and communities in which we operate;
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Consolidate initial land/property positions to build operating efficiency; and
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Assess and close opportunities expeditiously; manage asset and drilling portfolios on a continuous basis; high-grade material opportunities for drilling and drop those with no scope to create value.
Our access to opportunities stems from a combination of experience and industry relationships of the management team and board of directors, both within and outside of South America. An active market with many available deals is critical to growing a portfolio efficiently and effectively so that we can capitalize on our capabilities today and into the future as we grow in scale and our capabilities evolve.
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 is the purchaser of most of our crude oil sold in Colombia. We deliver our oil to Ecopetrol through our transportation facilities which include pipelines, gathering systems and trucking. We completed pipelines in 2008 to connect our oil from our discoveries at Juanambu and Costayaco to our existing pipeline system, replacing previous transportation by truck. In 2009, under our current development plan, we expect to reach the maximum production rate from the fields in the Putumayo Basin of about 28,000 BOPD before royalties. The majority of the oil produced will be transported by pipeline. About 5,000 BOPD gross will be trucked from Santana Station to Ecopetrol’s storage terminal at Orito. Another 5,000 BOPD gross will be trucked from Costayaco to Ecopetrol’s storage terminal at Neiva, which is approximately 300 kilometers north of the Chaza block. Crude oil prices for sales to Ecopetrol are defined by a multi-year contract with Ecopetrol, based on West Texas Intermediate (“WTI”), price less adjustments for quality and transportation. These contracts are subject to renegotiation periodically and generally contain mutual termination provisions with thirty days notice. Our oil in Colombia is good quality light oil. We receive 25% of our revenue in Colombian pesos, and 75% of revenue in US dollars. Sales to Ecopetrol accounted for 89% of our revenues in 2008, 75% of our revenues in 2007, and 56% of our revenues in 2006. We also sell a small amount of oil to Metapetrol in Colombia, and that accounted for 2% of revenue in 2008.
Gas produced on the Magangue block 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 2008. We had no sales to Surtigas prior to 2008.
In accordance with our debt facility with Standard Bank PLC, we are required to hedge a portion of production from our Colombian operations. We entered into a costless collar financial derivative contract for crude oil based on WTI price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period for 400 barrels of oil per day from March 2007 to December 2007, 300 barrels of oil per day from January 2008 to December 2008, and 200 barrels of oil per day from January 2009 to February 2010.
We market our own share of production in Argentina. Our oil in Argentina is good quality light oil. The purchaser of most of our oil in Argentina is Refineria del Norte S.A. (“Refiner S.A.”) Starting in December 2008, we are shipping two truckloads per day from our El Chivil field to Polipetrol S.A. in the Mendoza Province. In Argentina export prices for crude oil are subject to an export tax based on WTI price. An amount equivalent to the export tax is applied to domestic sales, which has the effect of limiting the actual realized price for domestic sales. Our crude oil prices are agreed on a spot basis with our refiners, 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 US dollar prices with the exchange rate fixed on the sales invoice date. Our contract with Refiner S.A. expired January 1, 2008; however, we are continuing sales of our oil under oral agreement with Refiner S.A, and spot sales contracts. See “Negative Economic, Political and Regulatory Developments in Argentina, Including Export Controls, May Negatively Affect our Operation” in Item 1A
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, initially in Colombia, Argentina, and Peru, with the intention of expanding elsewhere into other countries. Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, factors affecting our industry or the regions in which we operate will likely impact us more acutely than if our business was more diversified.
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 cash balances and cash flow from operations and existing credit facilities will be sufficient only to fund our currently planned activities. We will require additional capital to continue to operate our business beyond our current planned activities and 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. The current situation in world capital markets has made it increasingly difficult for companies to raise funds. 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 future financing transactions. 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 condition.
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 and 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 cease our operations.
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 management and other personnel in conducting the business of Gran Tierra. We have a small management team consisting of Dana Coffield, our President and Chief Executive Officer, Martin Eden, our Vice President, Finance and Chief Financial Officer, Max Wei, our Vice President, Operations (who is retiring in March 2009), Shane O’Leary, our Chief Operating Officer starting on March 2, 2009, Rafael Orunesu, our President of Gran Tierra Argentina SA, and Edgar Dyes, our President of Gran Tierra Colombia Ltd. (“Gran Tierra Colombia”). The loss of any of the continuing individuals or our inability to attract suitably qualified staff 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 who are willing to work in that jurisdiction. We do not currently carry life insurance for our key employees.
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.
Unanticipated Problems in Our Operations May Harm Our Business and Our Viability.
If our operations in South America are disrupted and/or the economic integrity of these projects is threatened for unexpected reasons, our business may experience a setback. These unexpected events may be due to technical difficulties, operational difficulties which impact the production, transport or sale of our products, geographic and weather conditions, business reasons or otherwise. Prolonged problems may threaten the commercial viability of our operations. Moreover, the occurrence of significant unforeseen conditions or events in connection with our acquisition of operations in South America may cause us to question the thoroughness of our due diligence and planning process which occurred before the acquisitions, and may cause us to reevaluate our business model and the viability of our contemplated business. Such actions and analysis may cause us to delay development efforts and to miss out on opportunities to expand our operations.
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.
Local Legal and Regulatory Systems in Which We Operate May Create Uncertainty Regarding Our Rights and Operating Activities, Which May Harm Our Ability to do Business.
We are a company organized under the laws of the State of Nevada and are subject to United States laws and regulations. The jurisdictions in which we operate our exploration, development and production activities may have different or less developed legal systems than the United States, which may result in risks such as:
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effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or, in an ownership dispute, being more difficult to obtain;
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a higher degree of discretion on the part of governmental authorities;
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the lack of judicial or administrative guidance on interpreting applicable rules and regulations;
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inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; and
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relative inexperience of the judiciary and courts in such matters.
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.
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 properties and to consummate transactions in a highly competitive environment. These realities 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 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 in order 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, 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 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.
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.
We May Not Be Able To Effectively Manage Our Growth, Which May Harm Our Profitability.
Our strategy envisions expanding our business. If we fail to effectively manage our growth, 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 employees. We may not be able to:
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expand our systems effectively or efficiently or in a timely manner;
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allocate our human resources optimally;
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identify and hire qualified employees or retain valued employees; or
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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.
We May Have Difficulty Distributing Our Production, Which Could Harm Our Financial Condition.
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 will 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.
Maintaining and Improving Our Financial Controls May Strain Our Resources and Divert Management's Attention, and If We Are Not Able to Report That We Have Effective Internal Controls Our Stock Price May Suffer.
We are subject to the requirements of the Securities Exchange Act of 1934, or the Exchange Act, including the requirements of the Sarbanes-Oxley Act of 2002. The requirements of these rules and regulations have caused us to incur significant legal and financial compliance costs, make some activities more difficult, time consuming or costly and may also place undue strain on our personnel, systems and resources. The Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal controls over financial reporting. This can be difficult to do. As a result of this and similar activities, management's attention may be diverted from other business concerns, which could have a material adverse effect on our business, financial condition and results of operations.
At year end 2007 and during the first three quarters of 2008, we had a material weakness in our internal control over financial reporting. Significant resources were required to remediate this weakness. If we have one or more additional material weaknesses in the future, there is a possibility that this could result in a restatement of our financial statements or impact our ability to accurately report financial information on a timely basis, which could adversely affect our stock price. Further, the presence of one or more material weaknesses could cause us to not be able to timely file our periodic reports with the SEC, which could also result in law suits or diversion of management's attention from our business.
Integration of Gran Tierra and Solana’s Businesses, Personnel and Financial Controls May Be More Difficult Than Expected, Which Could Strain the Combined Company’s Operations.
In 2009, Gran Tierra will need to undertake significant efforts to integrate its personnel, accounting and other systems, and operations. This can be difficult to do and will require significant management and other resources. For example, the combined company will be subject to the requirements of the Sarbanes-Oxley Act of 2002, to which Solana has not been subject. If there are difficulties in integrating Solana’s systems into the Gran Tierra systems so that the combined company cannot meet all of its requirements under the Sarbanes-Oxley Act, this could cause a significant diversion of management’s attention from running the business, may cause us to report one or more material weaknesses in our internal control over financial reporting, may cause other failures to comply with the Sarbanes-Oxley Act, or may be expensive in legal, financial or other costs to cause our company to become compliant, any of which could be time-consuming or costly and may also place undue strain on the personnel, systems and resources of the our company and cause the stock price of our company to decline.
Guerrilla Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned About Safeguarding Our Operations and Personnel in Colombia.
A 40-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups - both funded by the drug trade - continues in Colombia. Insurgents continue to attack civilians and violent guerilla activity continues in many parts of the country.
We have interests in five oil producing basins in Colombia - in the Middle Magdalena, Lower Magdalena, Llanos, Putumayo and Catatumbo basins. The Putumayo and Catatumbo regions have been prone to guerilla activity in the past. In 1989, Argosy’s facilities in one field were attacked by guerillas and operations were briefly disrupted. Pipelines have also been targets, including the Trans-Andean export pipeline which transports oil from the Putumayo region. In March and April of 2008, sections of one of the Ecopetrol pipelines were blown up by guerillas, which temporarily reduced our deliveries to Ecopetrol in the first quarter of 2008. Ecopetrol was able to restore deliveries within two weeks of these attacks and currently there are no interruptions to our deliveries.
Continuing attempts 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. Continued or heightened security concerns in Colombia could also result in a significant loss to us.
Our Oil Sales Will Depend on a Relatively Small Group of Customers, Which Could Adversely Affect Our Financial Results
Oil sales in Colombia are made 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 two customers. 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.
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
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 and Peru, and expect to expand our operations into 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 labour 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 and other 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. 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 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, 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.
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.
Negative Economic, Political and Regulatory Developments in Argentina, Including Export Controls May Negatively Affect our Operations.
The Argentine economy has experienced volatility in recent decades. This volatility has included periods of low or negative growth and variable levels of inflation. Inflation was at its peak in the 1980’s and early 1990’s. In late-2001 there was a deep fiscal crisis in Argentina involving restrictions on banking transactions, imposition of exchange controls, suspension of payment of Argentina’s public debt and abrogation of the one-to one peg of the peso to the dollar. For the next year, Argentina experienced contractions in economic growth, increasing inflation and a volatile exchange rate. Subsequently, Argentina experienced a period of GDP growth, normalized inflation, and strengthened public finances. However, there is no guarantee of economic stability. The economy faltered and the government experienced some difficulty in 2008. Inflation has been rising and government popularity has dropped, due to the economic situation and the unpopularity of some of the programs the government tried to implement to deal with it. The government applied export controls to agricultural products which were highly unpopular and caused demonstrations and labour strikes across the country.
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.
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.
Our agreements with Refiner S.A. expired on January 1, 2008, and renegotiation, though currently underway, has been delayed due to the introduction of a new withholding tax regime for crude oil and refined oil products exported and sold domestically in Argentina. Currently all oil and gas producers in Argentina are operating without sales contracts. The new withholding tax regime was introduced without specific guidance as to its application. Producers and refiners of oil in Argentina have been unable to determine an agreed sales price for oil deliveries to refineries. Also, the price for refiners’ gasoline production has been capped below the price that would be received for crude oil. Therefore, 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 deliveries to the refinery. In our case we are negotiating sales on a spot price basis with two refineries. Refiner S.A. takes most of our oil and the price is negotiated on a month by month basis. We deliver two truckloads per day to Polipetrol in Mendoza province, and that price is negotiated weekly. 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. We are working with other oil and gas producers in the area, as well as Refiner S.A., and provincial governments, to lobby the federal government for change.
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:
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all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended;
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the Export-Import Bank of the United States and the Overseas Private Investment Corporation would not approve financing for new projects in Colombia;
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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
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the President of the United States and Congress would retain the right to apply future trade sanctions.
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 the Colombian national oil company 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.
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. In order 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 lacking in 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 and share price.
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 is primarily invoiced in United States dollars, but payment is also made in Argentine and Colombian 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 3.51 pesos to the US dollar, a fluctuation of approximately 15%. 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%.
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.
We Must Maintain Effective Registration Statements For All of Our Private Placements of Our Common Stock.,
We are required to file Post Effective Amendments to our registration statements periodically in accordance with the Registration Rights Agreements for our 2005 and 2006 private placements of units. Amending and keeping these registration statements effective is costly and diverts management’s attention from running our business. Failure to maintain these registration statements could result in the loss of ability for some shareholders to trade their shares, and could effect the price of our stock.
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 Could Cause Significant Delays and Expenses That Could Materially Impact Our Business.
We are subject to licensing and permitting requirements relating to drilling for oil and natural gas. We may not be able to obtain, sustain or renew such licenses. Regulations and policies relating to these licenses and permits may change or be implemented in a way that we do not currently anticipate. 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 will make estimates of oil and natural gas reserves, upon which we will base our financial projections. We will 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.
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 in effect at the time of the calculation are 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 SEC 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.
Drilling New Wells 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. 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 will 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.
Drilling Oil and Gas Wells and Production and Transportation Activity Could be Hindered by Earthquakes and Weather-Related Operating Risks.
We are subject to operating hazards normally associated with the exploration and production of oil and gas, including blowouts, explosions, oil spills, cratering, pollution, earthquakes, hurricanes, and fires. The occurrence of any such operating hazards could result in substantial losses to us due to injury or loss of life and damage to or destruction of oil and gas wells, formations, production facilities or other properties.
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. Without other transportation alternatives, sales of oil could be disrupted by landslides or other natural events which impact this pipeline.
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.
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 in 2000 was $30 per barrel. In 2006, it was $66 per barrel, in 2007 it was $72 per barrel and in 2008 it was $100 per barrel. However, the average price for December 2008 was $41 per barrel, 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 differences. 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 as a result are 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.
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.
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.
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:
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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 future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;
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announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;
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fluctuations in revenue from our oil and natural gas business;
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changes in the market and/or WTI price for oil and natural gas commodities and/or in the capital markets generally;
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changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels; and
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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:
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quarterly variations in our revenues and operating expenses;
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changes in the valuation of similarly situated companies, both in our industry and in other industries;
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changes in analysts’ estimates affecting our company, our competitors and/or our industry;
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changes in the accounting methods used in or otherwise affecting our industry;
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additions and departures of key personnel;
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announcements of technological innovations or new products available to the oil and natural gas industry;
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announcements by relevant governments pertaining to incentives for alternative energy development programs;
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fluctuations in interest rates, exchange rates and the availability of capital in the capital markets; and
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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.
Our Operating Results May Fluctuate Significantly, and These Fluctuations May Cause Our Stock Price to Decline.
Our operating results will likely vary in the future primarily from fluctuations in our revenues and operating expenses, including the ability to produce the oil and natural gas reserves that we are able to develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.
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.
Gran Tierra may not have sufficient shares to acquire other businesses or assets.
The number of shares of Gran Tierra common stock outstanding or reserved for issuance under Gran Tierra’s outstanding exchangeable shares, warrants and options is approximately 270 million shares, leaving only approximately 30 million shares available to use for the purpose of acquiring additional businesses or assets. Gran Tierra may not have sufficient shares of its common stock authorized and available for issuance to acquire additional businesses without a vote of its stockholders, which could delay or prevent the consummation of additional transactions.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Offices
We currently lease office space in: Calgary, Alberta; Buenos Aires, Argentina; and Bogota, Colombia. The three Calgary leases expire January 31, 2011, January 31, 2013 and April 30, 2014 and cost $12,386 per month, $6,684 per month, and $12,600 per month respectively. We have subleased the third lease for $10,500 per month from February 1, 2009 to August 31, 2011. Our two Buenos Aires, Argentina leases expire January 31, 2012 and July 15, 2009 and cost $2,350 per month and $2,467 per month, respectively. We have six leases in Bogota, Colombia. One expires in March 31, 2009 and costs $794 per month, with the space used for storage. The second expires December 31, 2010 with costs of $30,321 per month. This space housed Gran Tierra’s staff prior to our acquisition of Solana. This space will be subleased for the remainder of the contract period. Three of the Bogota leases are for the space that housed Solana staff prior to the acquisition. These leases expire February 28, 2009 (this lease will renew automatically on that date and expire February 28, 2010, according to the terms of the lease), August 31, 2009 and July 31, 2010 with costs of $2,482 per month, $9,879 per month and $2,355 per month, respectively. The space governed by each of these leases will either be subleased or surrendered. If surrendered, we will have to pay a termination fee equal to three months rent for each lease. The sixth Bogota Lease expires February 1, 2012 and will house the newly combined staff from both Gran Tierra and Solana, at a cost of $72,478 per month. The properties remaining on lease are in excellent 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 Santana, Guayuyaco, Chaza and Mecaya blocks in the Putumayo basin in southwest Colombia; 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 the Putumayo TEAs in the Putumayo basin were acquired in 2007. We relinquished the Primavera block in 2007. We also are currently in the process of converting portions of the Putumayo TEAs to Exploration and Exploitation contracts.
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.
Currently, the Guayuyaco, Santana, Chaza and Guachiria blocks have producing oil wells and the Magangue block is producing natural gas.
Colombian royalties can vary between contract types, however all of the ANH contracts introduced in 2004 have a standardized royalty regime, and some of the Ecopetrol Association Contracts follow the same regime. The ANH contract royalties are based on a sliding scale 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%. ANH contracts have an additional royalty that applies when cumulative gross production 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. All of our blocks in Colombia fall under this methodology except as follows: Santana and Magangue Blocks have a flat 20% royalty; Guayuyaco and Rio Magdalena Blocks have the sliding scale royalty but do not have the additional royalty; the Guachiria block has the sliding scale royalty plus an additional 13% payable to Ecopetrol, but no other additional royalty. In addition to these government royalties, Gran Tierra’s original interests in the six blocks purchased from Argosy that we still hold (Santana, Guayuyaco, Chaza, Rio Magdalena, Talora, 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
The Santana block contract was signed in July 1987 and covers 1,119 acres and includes 15 producing wells in 4 fields - Linda, Mary, Miraflor and Toroyaco. Activities are governed by terms of a Shared Risk Contract with Ecopetrol, and we are the operator. 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 field 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 2008, we performed remedial work on various wells and changed the artificial lift system on one well in the Miraflor field, adding incremental production. For 2009, we plan to revamp our refinery and upgrade our fire control system and oil spill equipment.
Guayuyaco
The Guayuyaco block contract was signed in September 2002 and covers 52,366 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. Three wells are now producing, Guayuyaco-1 commenced production in February 2005, Guayuyaco-2 began production in September 2005 and Juanambu-1 began commercial production on November 8, 2007. Ecopetrol may 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 2027. 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 2008, we conducted two workovers on the Juanambu-1 well. In 2009, we plan to drill a second well on the Juanambu discovery, as well as upgrade facilities. In addition, we plan to acquire 50 square kilometers of 3D seismic, some of which may run over onto the Chaza block.
Rio Magdalena
The Rio Magdalena Association Contract with Ecopetrol was signed in February 2002. The Rio Magdalena block covers 144,670 acres and is located approximately 75 kilometers west of Bogota, Colombia. This is an exploration block and there are no reserves at this time. We are the operator of the block and hold a 40% working interest. We have two partners who hold 9% and 51% each. According to the terms of the exploration contract, we were committed to drill three exploration wells prior to February 2008. The first of these wells, Popa-1, was drilled in late 2006 and was subsequently plugged and abandoned after testing oil production at non-commercial rates. The drilling for the second exploration well, Caneyes-1, began in late December 2006 and the well was subsequently plugged and abandoned in February 2007. In 2008 we drilled the Popa-2 well, which encountered natural gas and natural gas liquids. This well was fully funded by our partners as part of the farm-in agreement for the block. 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 2009 we plan to drill one exploration well and conduct a long term production test of Popa-2 and acquire 75 square kilometers of 3D seismic.
Chaza
The Chaza block covers 80,242 acres and is governed by the terms of an Exploration and Exploitation Contract with ANH. 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. In 2008 we completed drilling Costayaco-2, which we had started at the end of 2007. We proceeded to drill three more successful development wells on the Costayaco discovery, with a fourth, Costayaco-6 completing testing in 2009. Costayaco-6 will be used for either water injection or water disposal, our engineering professionals are evaluating the alternatives. We also completed a 15km 8 inch pipeline to connect the Costayaco field to our existing pipeline infrastructure.
This block is in the fourth exploration period which carries the obligation to drill one exploration well and expires December 26, 2009. We plan to apply to ANH for one of our development wells to qualify as this exploration well. If that application is not successful, we will drill one exploration well in 2009. There are two further exploration periods: period five lasts 12 months and has an obligation to drill one exploration well; period six lasts six months and also has an obligation to drill one exploration well. The contract for this field expires in two phases. The exploration phase expires in 2011 and the production phase ends in 2032. The property will be returned to the government upon expiration of the production contract. Within sixty days following the date of the return of the property, we must carry out an abandonment program to the satisfaction of ANH. In conjunction with the abandonment, we must establish and maintain an abandonment fund to ensure that financial resources are available at the end of the contract.
In 2009, we plan to drill 4 development wells and one injector well. One of these wells (Costayaco-7) commenced drilling on February 13, 2009. One exploration well may be drilled, as noted above. We plan to conduct 3 workovers, acquire 9 kilometers of 2D seismic and work on various support facilities including trunk lines, water disposal and pumping stations.
Talora
We currently hold a 20% working interest and are the operator for the Talora block. The Exploration and Exploitation Contract associated with the block was originally signed in September 2004, providing for a six year exploration period and 24 year production period. The Talora contract area covers 108,334 acres and is located approximately 75 kilometers west of Bogota, Colombia. This is an exploration block and there are currently no reserves. The fourth exploration period has begun and we have a commitment to drill one well, which commenced drilling on January 8, 2009 and recently completed the drilling phase at no cost to us. The well is currently being tested. A third party partner is paying the cost of this well. Once this well is completed, we intend to apply to ANH to have our entire 20% interest in the Talora block assigned to the third party, per our agreement with them. The property will be returned to the government upon expiration of the production contract.
Mecaya
The Mecaya Exploration and Exploitation contract was signed June 2006. The Mecaya contract area covers 74,128 acres in southern Colombia, about 150 kilometers southeast of Pasto. We are the operator and currently have a 15% participation interest and two partners have 55% and 30% each. In 2008, we acquired 15km of 2D seismic. We are in exploration period two of this contract and are obliged to drill one exploration well, and re-enter a previously drilled well. We are contractually obligated to complete this work by June 2009. 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 2009, we plan to complete the period two obligations described above, by drilling one exploration well and re-entering another.
Azar
We acquired an 80% interest in the Azar property through a farm-in in late 2006. This exploration block covers 51,639 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%. In 2008, we acquired 40 square kilometers of 3D seismic and performed one well re-entry on the Palmera 1 well, encountering oil. This block is in the third exploration period until October 11, 2009, with an obligation to drill one exploration well before such date. We have received approval to swap this exploration well commitment with a commitment to acquire seismic. There are 3 more exploration periods that follow, each lasting 12 months and including an obligation to drill one exploration well. The exploration contract expires in 2012 for this property. The exploitation phase expires 24 years after commerciality is approved. The property will be returned to the government upon expiration of the production contract. If we make a commercial discovery on the block, and produce oil, we will be obligated to perform abandonment activities, under the same conditions as those for the Chaza block.
In 2009, we plan to drill one exploration well, conduct a long term production test on the Palmera 1 well and acquire 50 square kilometers of 3D seismic and 40 kilometers of 2D seismic in satisfaction of the exploration commitment for the third exploration period.
Putumayo A&B Technical Evaluation Areas
We were awarded two Technical Evaluation Areas in the Putumayo Basin in southern Colombia in June 2007. The two Technical Evaluation Areas are located near the Orito Field, the largest known oil field in the Putumayo Basin.
Putumayo West A covers an area of 230,671 hectares (570,000 acres) and is held 100% by us. During the evaluation period, which expired in 2008, we conducted 400 kilometers of seismic reprocessing and geologic studies. We had a preferential right to apply for exploration and exploitation contracts on the evaluation area, and have applied for two blocks within the original area. We are currently waiting for final approval from ANH. If approval is obtained, we will acquire 125 kilometers of 3D seismic over the two blocks in 2009.
Putumayo West B covers an area of 44,111 hectares (109,000 acres) and is held 100% by us. During the evaluation period, which expired in 2008, we conducted 100 kilometers of seismic reprocessing and geologic studies. We have applied to convert this Technical Evaluation Agreement to an Exploration and Exploitation contract in the area and are awaiting final approval from ANH. If approval is obtained, we will acquire 60 kilometers of 2D seismic over the block in 2009.
The following blocks were acquired by Gran Tierra as part of the acquisition of Solana Resources Limited, which closed November 14, 2008.
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 acres. We are the operator of the block with a 37.8% working interest and our partners Ecopetrol and another third party each have a 58% and a 4.2% working interest, respectively. 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 2009, we have no plans for additional exploration or development work.
Catguas Block
Solana acquired the Catguas block in November 2005. We are the operator of the block which covers 393,150 acres in the Catatumbo Basin, and we hold a 100% working interest. In the southern 70% of the block, two partners together have a 15% beneficial interest, and a 50% beneficial interest in the remainder. 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, and this period expires November 16, 2009, and has an obligation to drill one exploration well. All remaining periods are 12 months in length and carry a work obligation of 1 well. The exploitation phase would last 24 years from any declaration of a commercial discovery.
In 2009, we plan to drill one exploration well, and re-enter another well, both on the southern portion of the block where we have an 85% working interest.
Guachiría Norte Block
Solana acquired the Guachiria Norte block in December 2004. We are the operator of the 101,819 acre block, located in the Llanos Basin, with a 100% working interest. A third party has a 30% beneficial interest in this block. The block is located approximately 250 km northeast of Bogotá and is subject to an ANH contract. It is an exploration block with no production.
We are in period four of the exploration phase of this contract which carries a two well drilling commitment expiring March 21, 2009. The first well to satisfy this commitment, Zafiro-1, was drilled in November 2008 and was dry. We plan to drill one exploration well in the first quarter of 2009, and this will satisfy the remaining commitment for the phase. There are a total of six exploration periods in the contract, the remaining two of which are 12 months each and carry a work obligation of one exploration well each. The exploitation phase would last 24 years from any declaration of a commercial discovery.
San Pablo Block
Solana acquired the San Pablo block in June 2007, which covers 104,535 acres and is situated immediately to the west of the Guachiría Sur Block. We are the operator and hold a 100% working interest in this block.
There are no wells producing on this block. We are in the second exploration period, which carries one well obligation and expires June 24, 2009. We plan to drill this exploration well in 2009. There are a total of 6 exploration periods and each period lasts 12 months and carries an obligation for one exploration well. The exploitation phase would last 24 years from any declaration of a commercial discovery.
Guachiría Block
We are the operator of the 18,499 acre Guachiría Block with a 100% working interest. A third party has a 30% beneficial interest in this block. The block adjoins the Guachiría Norte Block immediately to the south. Solana acquired this block from Ecopetrol, and it is subject to an ANH contract. We are in the fifth exploration period for this block, which expires in May 31, 2009. There are a total of 6 exploration periods, the final period lasting 12 months with a work obligation of one exploration well. The drilling commitment for the current period was fulfilled in 2008 by drilling the Los Acietes well. There are two producing wells on this block however they are currently shut in while we install permanent production facilities to replace facilities that were rented. The shut-in commenced on February 4 for one well and February 5 for the other, and is expected to last until the end of March. The contract expires in 2031.
In 2009, we plan to reprocess seismic, work on facilities and abandon the Yalea well, which ceased production in 2008.
Guachiría Sur Block
Solana acquired the Guachiria Sur block in October 2005. We are the operator of the 90,491 acre block with a working interest of 100%. A third party has a 30% beneficial interest in this block. The block is to the west and the south of the Guachiría Block and to the south of the Guachiría Norte Block. This block is subject to an ANH contract. It is an exploration block with no production.
We are currently in the fourth exploration period of this contract, and this period expires October 25, 2009. There are a total of 6 exploration periods, each lasting 12 months and each carrying an obligation to drill one exploration well. The exploitation phase would last 24 years from any declaration of a commercial discovery. The exploration contract originally required one well to be drilled for the current period, however we have swapped that obligation for an obligation to obtain 110 square kilometers of 3D seismic, which is planned for 2009.
Garibay Block
Solana acquired the Garibay block in October 2005. The block covers 75,936 acres and we have a working interest of 50%. The block is located approximately 170 km east of Bogotá and is subject to an ANH contract. On November 17, 2007, a farm-in 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 period four of the exploration contract, which expires October 24, 2009. There are a total of 6 exploration periods, each lasting 12 months and requiring one exploration well.
We have swapped 100 square kilometers of 3D seismic in exchange for the original contract’s obligation of one exploration well for the current period. Acquisition of this seismic began in early 2009.
Oil and Gas Properties - Argentina
In September 2005, we entered Argentina through the acquisition of a 14% interest in the Palmar Largo joint venture, and a 50% interest in each of the Nacatimbay and Ipaguazu blocks. In 2006, we purchased further properties in Argentina, including the remaining 50% interest in Nacatimbay and Ipaguzau, a 50% interest in El Vinalar and 100% interests in El Chivil, Valle Morado, Surubi and Santa Victoria. Our Argentina properties are located in the Noroeste Basin in northern Argentina.
Palmar Largo
The Palmar Largo joint venture block encompasses 341,500 acres. This asset is comprised of several producing oil fields in the Noroeste Basin. 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. At expiry of the block rights, ownership of the producing assets will revert to the provincial government.
Our work program for 2009 involves optimization of well performance and operating expenses to maximize net revenues from the property.
Nacatimbay
We acquired a 100% working interest in the Nacatimbay block through two transactions. We purchased a 50% working interest in September 2005 and we purchased the remaining 50% working interest in November 2006. Production from the Nacatimbay oil, gas and condensate field began in 1996. Three wells were drilled and one produced on and off until 2007. We attempted a re-entry on another well on the block in 2008, but were unsuccessful. We have started the process of surrendering this block to the Province of Salta.
The Nacatimbay block rights expire in 2022 with a provision for a ten year extension if a discovery is made. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government.
Ipaguazu
We acquired a 100% working interest in the Ipaguazu block through two transactions. We purchased a 50% working interest in September 2005 and we purchased the remaining 50% working interest in November 2006. 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 acres and has not been fully appraised, leaving scope for both reactivation and exploration in the future. The Ipaguazu block rights expire in 2016 with a ten year extension if a discovery is made. We do not have any outstanding work commitments. At expiry of the block rights, ownership of the producing assets will revert to the provincial government. In 2008, we successfully re-entered a well on this block. Production facilities are being installed in the first quarter of 2009. Once these facilities are complete, production from this well will commence.
El Vinalar
We acquired a 50% working interest in the El Vinalar Block in June 2006. This acquisition added a significant new land position and a small amount of production. El Vinalar covers 59,080 acres and contains a portfolio of exploration leads and oil field enhancement opportunities. Two successful workovers were conducted in 2008, each of which added a small amount of incremental production.
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 2009, we plan to continue regular field maintenance activities in El Vinalar.
El Chivil
We purchased El Chivil in November and December 2006, along with Surubi, Valle Morado and Santa Victoria. We are the operator and hold a 100% working interest in El Chivil. The Chivil field was discovered in 1987. Three wells were drilled; two remain in production. The field has produced 1.5 million barrels of oil to date. The contract for this field expires in 2015 with the option for a ten year extension. In 2008, we installed a new artificial lift system in one well, which increased production.
In 2009, we plan to acquire 112 square kilometers of 3D seismic on this block.
Surubi
We are the operator of the Surubi block 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 are paying their share of well costs from their share of production from Proa-1.
In 2009, we plan to acquire 50 square kilometers of 3D seismic.
Valle Morado, Santa Victoria
We purchased working interests in Valle Morado and Santa Victoria blocks in November and December 2006. These properties added to our existing portfolio of exploration and development opportunities.
Valle Morado 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 a single well, and was shut-in in 2001 due to water incursion. In 2008, we successfully re-entered the well. In 2009 we plan to conduct a feasibility study of production.
Santa Victoria covers 1,033,642 acres. It is an exploration block with no production history.
Oil and Gas Properties - Peru
We entered Peru in 2006 through the award by the government of Peru of two frontier exploration blocks.
Blocks 122 and 128
We were awarded two exploration blocks in Peru in the last quarter of 2006 under a license contract for the exploration and exploitation of hydrocarbons. Block 122 covers 1,217,651 acres and block 128 covers 2,218,389 acres. The blocks are located in the eastern flank of the Maranon Basin in northern Peru, on the crest of the Iquitos Arch. There is a 5-20%, sliding scale, royalty rate on the lands, dependent on production levels. Production less than 5,000 barrels of oil per day attracts a royalty of 5%, for production between 5,000 and 100,000 barrels of oil per day there is a linear sliding scale between 5% and 20%. Production over 100,000 barrels per day has a royalty of 20%.The exploration contracts expire in 2014 and work commitments are defined in four exploration periods spread over seven years. There is a financial commitment of $5 million over the seven years for each block which includes technical studies, seismic acquisition and the drilling of exploration wells. Acquisition of technical data through aeromagnetic-gravity studies began in 2007, and was completed in the first half of 2008, with a total of 20,000 kilometers of data acquired over both blocks. In 2008, we started EIA’s and the community consultation process. These projects will be completed in 2009, along with drilling feasibility and geological studies. Toward the end of 2009, we will initiate the acquisition of 540 kilometers of 2D seismic, to be completed in 2010. The production contract expires in 2037.
Proved Reserves
No estimates of proved reserves comparable to those included herein have been included in a report to any federal agency other than the SEC.
The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A. “Risk Factors”. As a result we have developed internal policies for estimating and evaluating reserves, and 100% of our reserves are audited by an independent reservoir engineering firm, GLJ Associates Ltd., at least annually.
The SEC definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:
·
Proved oil and natural gas reserves. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made as defined in Rule 4-10(a)(2). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
a)
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
b)
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
c)
Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
·
Proved developed reserves - Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as defined in Rule 4-10(a)(3).
·
Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required as defined in Rule 4-10(a)(4).
The following table sets forth our proved oil reserves net of all royalties and third party interests as of December 31, 2008 (all quantities in thousands of barrels of oil).
Our proved developed oil reserves set forth in the previous table, totaling 10.3 million barrels of oil as at December 31, 2008 consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2008 (all quantities in thousands of barrels of oil).
In addition to the oil reserves above, we have proved, developed, producing gas reserves of approximately 1.2 billion cubic feet (“BCF”), from the Magangue block in Colombia.
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, 2008 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”) Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities.
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, 2008.
Following are the results as of February 23, 2009 of wells in progress at December 31, 2008:
Well Statistics
The following table sets forth our producing wells as of December 31, 2008.
Developed and Undeveloped Acreage
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2008.
Item 3.
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. 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 $4.7 million.
Gran Tierra is in the process of settling several environmental matters inherited in the acquisition of Solana, that resulted in investigations and charges from Colombian environmental authorities, and an exchange infraction that resulted in a charge from the Superintendency of Corporations in Colombia. There are two charges related to the Guachiria Norte and Catguas blocks relating to encroaching on prescribed set back limits from bodies of water. No actual environmental damage occurred, however we expect to pay approximately $115,000 in penalties and approximately $3,000 in legal costs for each infraction. There is another charge relating to a block that Solana relinquished prior to the acquisition by Gran Tierra, relating to discharge of fluids and solids without treatment. We expect to pay approximately $115,000 in penalties plus $3,000 in legal fees. Finally, we expect to pay a fine for the exchange violation noted above in the amount of $115,000 and approximately $5,000 in legal costs. All of the above penalties and legal costs have been accrued in the financial statements.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
At the Special Meeting of Stockholders of Gran Tierra Inc. held on November 14, 2008, the following proposals were presented to the stockholders for adoption:
Proposal 1. To approve the issuance of shares of Gran Tierra common stock to be issued in connection with the acquisition of the outstanding securities of Solana Resources Limited:
As a result of these votes, Proposal 1 was approved.
Proposal 2. To approve an amendment to Gran Tierra’s articles of incorporation to create a new special voting share to enable the exchangeable shares to be issued in the proposed transaction with Solana Resources Limited to vote, as well as to make several technical changes:
Of the shares cast by the holder of the special voting share, there were 10,323,810 votes for to nil votes against with 1,544,328 votes abstaining cast. As a result of these votes, Proposal 2 was approved.
Proposal 3. To approve an amendment to Gran Tierra’s articles of incorporation to increase the total authorized number of shares of common stock from 300,000,000 to 600,000,000:
As a result of these votes, Proposal 3 was not approved, as a majority vote of the outstanding shares was not received.
Proposal 4. To approve an amendment to Gran Tierra’s articles of incorporation to change the board voting requirement for issuance of common stock from unanimous to a simple board action:
As a result of these votes, Proposal 4 was approved.
Proposal 5. To approve Gran Tierra’s 2007 Equity Incentive Plan, as amended and restated, to increase the number of shares available for issuance thereunder from 9,000,000 shares to 18,000,000 shares:
As a result of these votes, Proposal 5 was approved.
Executive Officers of the Registrant
Set forth below is information regarding our executive officers as of February 28, 2008.
Name
Age
Position
Dana Coffield
President and Chief Executive Officer; Director
Martin H. Eden
Chief Financial Officer
Shane O’Leary*
Chief Operating Officer
Max Wei**
Vice President, Operations
Rafael Orunesu
President and General Manager Gran Tierra Energy Argentina
Edgar Dyes
President and General Manager Gran Tierra Energy Colombia
*Commencing March 2, 2009
**Retiring March 12, 2009
Dana Coffield, President, Chief Executive Officer and Director. Before joining Gran Tierra as President, Chief Executive Officer and a Director in May, 2005, Mr. Coffield led the Middle East Business Unit for EnCana Corporation, North America’s largest independent oil and gas company, from 2003 through 2005. His responsibilities included business development, exploration operations, commercial evaluations, government and partner relations, planning and budgeting, environment/health/safety, security and management of several overseas operating offices. From 1998 through 2003, he was New Ventures Manager for EnCana’s predecessor - AEC International - where he expanded activities into five new countries on three continents. Mr. Coffield was previously with ARCO International for ten years, where he participated in exploration and production operations in North Africa, SE Asia and Alaska. He began his career as a mud-logger in the Texas Gulf Coast and later as a Research Assistant with the Earth Sciences and Resources Institute where he conducted geoscience research in North Africa, the Middle East and Latin America. Mr. Coffield has participated in the discovery of over 130,000,000 barrels of oil equivalent reserves.
Mr. Coffield graduated from the University of South Carolina with a Masters of Science degree and a doctorate (PhD) in Geology, based on research conducted in the Oman Mountains in Arabia and Gulf of Suez in Egypt, respectively. He has a Bachelor of Science degree in Geological Engineering from the Colorado School of Mines. Mr. Coffield is a member of the AAPG and the CSPG, and is a Fellow of the Explorers Club.
Martin H. Eden, Chief Financial Officer. Mr. Eden joined our company as Chief Financial Officer on January 2, 2007. He has over 27 years experience in accounting and finance in the energy industry in Canada and overseas. He was Chief Financial Officer of Artumas Group Inc., a publicly listed Canadian oil and gas company from April 2005 to December 2006 and was a director from June to October, 2006. He has been president of Eden and Associates Ltd., a financial consulting firm, from January 1999 to present. From October 2004 to March 2005 he was CFO of Chariot Energy Inc., a Canadian private oil and gas company. From January 2004 to September 2004, he was CFO of Assure Energy Inc., a publicly traded oil and gas company listed in the United States. From January 2001 to December 2002, he was CFO of Geodyne Energy Inc., a publicly listed Canadian oil and gas company. From 1997 to 2000, he was Controller and subsequently CFO of Kyrgoil Corporation, a publicly listed Canadian oil and gas company with operations in Central Asia. He spent nine years with Nexen Inc. (1986-1996), including three years as Finance Manager for Nexen’s Yemen operations and six years in Nexen’s financial reporting and special projects areas in its Canadian head office. Mr. Eden has worked in public practice, including two years as an audit manager for Coopers & Lybrand in East Africa. Mr. Eden holds a Bachelor of Science degree in Economics from Birmingham University, England, a Masters of Business Administration from Henley Management College/Brunel University, England, and is a member of the Institute of Chartered Accountants of Alberta and the Institute of Chartered Accountants in England and Wales.
Max Wei, Vice President, Operations. Mr. Wei is a Petroleum Engineering graduate from University of Alberta and has twenty-five years of experience as a reservoir engineer and project manager for oil and gas exploration and production in Canada, the US, Qatar, Bahrain, Oman, Kuwait, Egypt, Yemen, Pakistan, Bangladesh, Russia, Netherlands, Philippines, Malaysia, Venezuela and Ecuador, among other countries. Mr. Wei began his career with Shell Canada and later with Imperial Oil, in Heavy Oil Operations. He moved to the US in 1986 to work with Bechtel Petroleum Operations at Naval Petroleum Reserves in Elk Hills, California and eventually joined Occidental Petroleum in Bakersfield. Mr. Wei returned to Canada in 2000 as Team Leader for Qatar and Bahrain operations with AEC International and its successor, EnCana Corporation, where he worked until 2004. He completed a project management position with Petronas in Malaysia in April, 2005, before joining Gran Tierra in May, 2005.
Mr. Wei is specialized in reservoir engineering, project management, production operations, field acquisition and development, and mentoring. He is a registered Professional Engineer in the State of California and a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta. Mr. Wei has a BSc in Petroleum Engineering from the University of Alberta and Certification in Petroleum Engineering from Southern Alberta Institute of Technology. Mr. Wei will retire from Gran Tierra on March 12, 2009.
Shane P. O’Leary, Chief Operating Officer. Mr. O’Leary will be joining the company as Chief Operating Officer effective March 2, 2009. Mr. O’Leary, whose regional experience includes South America, North Africa, the Middle East, the former Soviet Union, and North America, will report to Dana Coffield, the company’s President and Chief Executive Officer.
Prior to joining Gran Tierra Energy, Mr. O’Leary was President and Chief Executive Officer of First Calgary Petroleums Ltd., an oil and gas company actively engaged in exploration and development activities in Algeria. From 2002 to 2006, Mr. O’Leary worked for Encana Corporation where his positions included Vice President of Development Planning and Engineering, as well as Vice President Brazil Business Unit. 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).
Rafael Orunesu, President and General Manager Gran Tierra Argentina. Mr. Orunesu joined Gran Tierra in March 2005 and brings a mix of operations management, project evaluation, production geology, reservoir and production engineering as well as leadership skills to Gran Tierra, with a South American focus. He was most recently Engineering Manager for Pluspetrol Peru, from 1997 through 2004, responsible for planning and development operations in the Peruvian North jungle. He participated in numerous evaluation and asset purchase and sale transactions covering Latin America and North Africa, incorporating 200,000,000 barrels of oil over a five-year period. Mr. Orunesu was previously with Pluspetrol Argentina from 1990 to 1996 where he managed the technical/economic evaluation of several oil fields. He began his career with YPF, initially as a geologist in the Austral Basin of Argentina and eventually as Chief of Exploitation Geology and Engineering for the Catriel Field in the Nuequén Basin, where he was responsible for drilling programs, workovers and secondary recovery projects.
Mr. Orunesu has a postgraduate degree in Reservoir Engineering and Exploitation Geology from Universidad Nacional de Buenos Aires and a degree in Geology from Universidad Nacional de la Plata, Argentina.
Edgar Dyes, President Argosy Energy / Gran Tierra Energy Colombia. Mr. Dyes joined our company through the acquisition of Argosy Energy International L.P., where he was Executive Vice-President and Chief Operating Officer. His experience in the Colombian oil industry spans twenty-one years, with the last six years in charge of Argosy Energy’s planning, management, finance and administration activities. Mr. Dyes began his career with Union Texas Petroleum as a petroleum accountant, where he eventually advanced into supervision and management positions in international operations for the company. He subsequently worked for Quintana Energy Corporation; Jackson Exploration, Inc.; CSX Oil and Gas; and Garnet Resources Corporation, where he held the position of Chief Financial Officer. Mr. Dyes has worked in various financial and management roles on projects located in the United Kingdom, Germany, Indonesia, Oman, Brunei, Egypt, Somalia, Ecuador and Colombia. Mr. Dyes holds a Bachelor’s degree in Business Management from Stephen F. Austin State University, with postgraduate studies in accounting.
Our above-listed officers have neither been convicted in any criminal proceeding during the past five years nor been parties to any judicial or administrative proceeding during the past five years that resulted in a judgment, decree or final order enjoining them from future violations of, or prohibiting activities subject to, federal or state securities laws or a finding of any violation of federal or state securities law or commodities law. Similarly, no bankruptcy petitions have been filed by or against any business or property of any of our directors or officers, nor has any bankruptcy petition been filed against a partnership or business association in which these persons were general partners or executive officers.
PART II
Item 5.
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock was first cleared for quotation on the OTC bulletin board on November 11, 2005 and traded from that time under the symbol “GTRE.OB.”, until April 8, 2008 when our common stock began trading on the NYSE Alternext (formerly American Stock Exchange) under the symbol “GTE”. On February 19, 2008, our common stock was listed on the TSX and is trading under the symbol “GTE”. On November 17, 2008, exchangeable shares in one of our subsidiaries, Gran Tierra Exchangeco, were listed on the TSX and are trading under the symbol “GTX”
As of February 23, 2009 there were approximately: 93 holders of record of shares of our common stock and 196,970,528 shares outstanding with $0.001 par value; and one share of Special A Voting Stock, $0.001 par value representing approximately 18 holders of record of 10,984,126 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 16 holders of record of 31,357,199 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into shares of our common stock.
On February 23, 2009, the last reported sales price of our shares on the NYSE Alternext was $2.17. For the periods indicated from January 1, 2007 to April 8, 2008, the following table sets forth the high and low bid prices per share of our common stock, which prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions. For the periods indicated from April 8, 2008 through the end of the fourth quarter of 2008, the following table shows the high and low sale prices per share of our common stock as reported on the NYSE Alternext (formerly American Stock Exchange).
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 facilities we are required to obtain the approval of one or both of the banks carrying our credit facilities for any dividend payments made by us exceeding $2 million in any fiscal year for Standard Bank PLC and $1 million for BNP Paribas.
Unregistered Sales of Equity Securities
On seven separate dates beginning on October 1, 2008 and ending on December 31, 2008, we sold an aggregate of 270,161 shares of our common stock for an aggregate purchase price of $316,369. These shares were issued to seven 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.
Performance Graph
Gran Tierra previously compared its stock price performance to the broad market index - Dow Jones Wilshire MicroCap index. However, due to the increase in the market capitalization and size of Gran Tierra, in large part due to the acquisition of Solana, Gran Tierra believes a more relevant broad market index for comparison purposes would be the Russell Small Cap Completeness index. As a result, Gran Tierra is providing both indices here, and in the future will no longer report the Dow Jones Wilshire MicroCap index.
Item 6.
Item 6. Selected Financial Data
(Thousands of U.S. Dollars, except per share amounts)
We made our initial acquisition of oil and gas producing and non-producing properties in Argentina in September 2005 for a total purchase price of approximately $7 million. Prior to that time we had no revenues. In June 2006, we acquired our Argosy assets for consideration of $37.5 million cash, 870,647 shares of our common stock and overriding and net profit interests in certain assets valued at $1 million. 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.
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 exploration, development and production. We are headquartered in Calgary, Alberta, Canada and operate in South America in Colombia, Argentina and Peru.
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 interest 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 February 2006 and an additional private placement that occurred in June 2006.
Effective November 14, 2008, we completed the acquisition of Solana Resources Limited (“Solana”). Upon completion of the transaction, Solana became an indirect wholly-owned subsidiary of Gran Tierra. Solana is an international resource company engaged in the acquisition, exploration, development and production of oil and natural gas. Solana is incorporated in Alberta, Canada with its head office in Calgary, Alberta. At the date of acquisition, Solana held various working interests in nine blocks in Colombia and was the operator of six of those blocks, four of which contained producing assets. As a result of the acquisition, Gran Tierra has increased its working interest in two of the producing blocks and has a working interest in seven new blocks.
The oil and gas industry has been adversely impacted by the downturn in the global economy and the decline in crude oil prices. Although our revenue has been negatively affected by these lower oil prices, our current liquidity position has mitigated the impact of these adverse market conditions. We believe that our current operations and capital expenditure program can be maintained from cash flow from existing operations, cash on hand and our credit facilities, barring unforeseen events. We also have the ability to defer or cancel portions of our capital expenditure program should our operating cash flows decline as a result of further reductions in crude oil prices.
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, and Peru; other regions will be considered 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 future 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. In the petroleum industry, geologic settings with proven petroleum source rocks, migration pathways, reservoir rocks and traps are referred to as petroleum systems.
Financial and Operational Highlights
Gran Tierra’s financial and operational results during the three-year period 2006 to 2008 reflect the success of our strategy since commencing operations in 2005:
·
We acquired oil and gas properties in Argentina, Colombia and Peru in 2005 and 2006, conducted an active exploration, drilling and development program in the three-year period, and further increased our oil and gas interests in Colombia through the acquisition of Solana in late 2008.
·
Gran Tierra’s estimated proved oil and gas reserves as at December 31, 2008, have tripled compared with December 31, 2007 and have increased by 540% since December 31, 2006. The contributing factors were the oil discoveries in Colombia as well as the acquisition of Solana.
·
Production of crude oil and natural gas (net of inventory adjustments) increased by 411% from 2006 to 2008, mainly due to the impact of production from the mid-2007 oil discovery in the Costayaco field in Colombia.
·
Increased production and higher oil prices resulted in an 845% increase in total revenues over the three-year period.
·
Net income for 2008 amounted to $23.5 million, or $0.19 per share, a significant improvement from the losses recorded in 2007 and 2006. Higher oil revenues were partially offset by increases in operating expenditures due to expanded Colombian operations, depletion expense associated with the acquisition of Solana and higher production levels, general and administrative expenses incurred due to expanded activities and regulatory compliance, foreign exchange losses associated with the acquisition of Solana, and income tax expense resulting from the profitability of Colombian operations. Prior year losses also included liquidated damages which represented damages payable to stockholders as a result of certain registration statements not becoming effective within the periods specified in the share registration rights agreements for the shares purchased as well as losses from derivative financial instruments.
·
Oil and gas property expenditures in 2008 and 2007 reflect the Costayaco field exploration and development program, the successful drilling of the Proa-1 exploration well in the Argentine Surubi block in 2008, and continued geological survey work carried out in Peru. The 2006 capital expenditures reflect the initial acquisition of oil and gas interests in Colombia and Argentina.
·
Our significant cash position of $176.8 million at December 31, 2008 resulted primarily from positive cash flows from operations as well as the net cash balance of $81.9 million acquired as part of the acquisition of Solana.
·
Property, plant & equipment as at December 31, 2008 was $767.6 million, a significant increase from prior years, reflecting our ongoing exploration and development program and recording of the Solana assets at their fair values of $682.0 million at the acquisition date.
Business Combinations
Solana Resources Limited
On November 14, 2008, Gran Tierra completed the acquisition of all of the outstanding common shares of Solana. Pursuant to the terms of the acquisition, each holder of Solana shares received either: (i) 0.9527918 of a share of Gran Tierra common stock for each Solana share held; or (ii) 0.9527918 of an exchangeable share of Gran Tierra Exchangeco Inc., a Canadian subsidiary of Gran Tierra, for each Solana share held. The share exchange resulted in Gran Tierra acquiring all of the 126,597,402 issued and outstanding common shares of Solana in exchange for 120,620,967 shares comprised of 51,516,332 shares of Gran Tierra common stock and 69,104,635 exchangeable shares. In addition, pursuant to the terms of the acquisition: (i) Gran Tierra issued options to acquire 466,869 shares of Gran Tierra common stock in exchange for 490,001 Solana options; and (ii) 7,500,000 Solana warrants outstanding at the date of the acquisition were assumed by Gran Tierra and are exercisable for 7,145,938 shares of Gran Tierra common stock (by applying the exchange ratio).
On November 14, 2008 and prior to the November 15, 2008 deadline, as contractually agreed, Gran Tierra also issued two million shares of Gran Tierra common stock to acquire the participating interest in Solana’s properties that, under the Colombian Participation Agreement entered into in 2006 as part of the acquisition of Argosy Energy International (“Argosy”), would otherwise accrue to the former owners of Argosy. The shares were issued in a private placement and the resale of the shares was registered pursuant to a registration rights agreement.
Upon completion of the transaction, Solana became an indirect wholly-owned subsidiary of Gran Tierra. On a diluted basis, upon the closing of the acquisition, Solana and Gran Tierra security holders owned approximately 49% and 51% of the combined company, respectively.
The acquisition was accounted for using the purchase method, with Gran Tierra being the acquirer, whereby the Solana assets acquired and liabilities assumed were recorded at their fair values at the acquisition date of November 14, 2008 and the results of Solana have been consolidated with Gran Tierra since that date. The fair value of Gran Tierra’s shares was determined as the weighted average closing price of the common shares of Gran Tierra for the five-day period around the announcement date of July 29, 2008, being two days prior to and after the acquisition was agreed to and announced, and the announcement date. The fair value of each exchangeable share issued is equal to the fair value of a common share of Gran Tierra. The following tables show the purchase price and its allocation to the fair value of assets acquired and liabilities assumed:
Argosy Energy International
On June 20, 2006, Gran Tierra acquired all of the limited partnership interests of Argosy and all of the issued and outstanding capital stock of Argosy Energy Corp. from Crosby Capital LLC. Consideration paid to Crosby consisted of $37.5 million cash, 870,647 shares of Gran Tierra common stock and overriding and net profit interests in certain of Argosy’s assets valued at $1 million. The acquisition was accounted for using the purchase method, and the results of Argosy have been consolidated with Gran Tierra from June 20, 2006.
Consolidated Results of Operations
1)
The 2008 results include the operations of Solana subsequent to our acquisition of Solana on November 14, 2008.
2)
Gas volumes are converted to barrels of oil equivalent (“boe”) at the rate of 20 thousand cubic feet ("mcf") of gas per barrel of oil based upon the approximate relative values of natural gas and oil. Natural gas liquid (“NGL”) volumes are converted to boe on a one-to-one basis with oil.
3)
Production represents production volumes adjusted for inventory changes.
Consolidated Results of Operations for the Year Ended December 31, 2008 compared to the Results for the Year Ended December 31, 2007
In 2008, a 145% increase in crude oil production and a 44% increase in realized prices of crude oil were the major contributing factors to net income of $23.5 million compared to a net loss of $8.5 million recorded in 2007.
Our revenue and interest increased 253% to $114.0 million in 2008 compared to 2007 due to increased production and higher crude oil prices. Crude oil and NGL production in 2008 increased to 1,328,145 barrels compared to 541,069 barrels in 2007 due to the inclusion of a full year of production from the Costayaco and Juanambu fields in Colombia. These fields were discovered in 2007 and the discovery wells came on production during the second half of 2007. In 2008, we drilled and completed four development wells at Costayaco and these wells were put on production during the course of the year. Average realized crude oil prices increased to $84.89 per barrel from $58.79 per barrel in 2007 reflecting the higher West Texas Intermediate (“WTI”) oil prices experienced during the first three quarters of 2008. Solana properties also contributed to the overall production levels since acquisition.
Operating expenses for 2008 amounted to $19.2 million, an 83% increase from the prior year. The increase was primarily due to the increased production in Colombia as well as the addition of the post-acquisition operating expenses of Solana which amounted to $3.6 million. However, in 2008, the new fields in Colombia with high production wells and lower operating expenses resulted in operating expenses of $14.46 per boe, a 25% decline from 2007.
In 2008, higher production levels as well as the amortization of $6.9 million related to the recording of Solana’s property, plant and equipment at fair value resulted in a 173% increase in depletion, depreciation and accretion (“DD&A”) to $25.7 million. A 12% increase in the average depletion rate to $19.37 per boe in 2008 was primarily due to the significant additions to the proved depletable cost base partially offset by higher proved reserves in Colombia.
General and administrative (“G&A”) expenses of $18.6 million for 2008 was 82% higher than 2007 due to increased salaries and benefits and stock-based compensation of $5.5 million mainly as a result of the expanded operations in Colombia and the 2008 option grants, as well as higher corporate stewardship costs including Sarbanes-Oxley compliance requirements and ongoing expenses related to securities registration.
Other expenses of $6.0 million in 2008 represent primarily a foreign exchange loss which resulted from the translation of a deferred tax liability recorded on the purchase of Solana. This deferred tax liability, a monetary liability, is denominated in the local currency of Colombia and as a result, a foreign exchange loss has been calculated on conversion to the US dollar functional currency. Other expenses in 2007 comprised mainly liquidated damages of $7.4 million and financial derivatives losses of $3.0 million. Liquidated damages represented damages payable to stockholders as a result of certain registration statements not becoming effective within the periods specified in the share registration rights agreements for the underlying securities. There were no liquidated damages in 2008. Financial derivative losses represented losses recorded from the costless collar financial derivative contract of crude oil prices entered into pursuant to the terms and conditions of Gran Tierra’s credit facility. There were no significant gains or losses related to financial derivative instruments in 2008.
Income tax expense for 2008 amounted to $20.9 million compared to $0.3 million recorded in 2007. The increase resulted primarily from the Colombian operations which generated net income before taxes of $58.5 million in 2008 compared to $11.5 million recorded in 2007. Our Colombian operations claimed incentives in 2008 as a result of increased additional Colombian tax capital investment in producing oil and natural gas properties. These additional tax incentives decrease our current income tax otherwise payable by approximately $3.8 million. The tax expense related to our Colombian operating segment was $22.1 million, offset by a recovery of $1.1 million for our Argentina segment.
Consolidated Results of Operations for the Year Ended December 31, 2007 as compared to the Results for the Year Ended December 31, 2006
For the year ended December 31, 2007, Gran Tierra recorded a net loss of $8.5 million compared to a net loss of $5.8 million recorded in 2006. Increased revenue levels from higher crude oil production and prices were more than offset by higher operating and general and administrative expenses associated with the expanded activity levels as well as increased corporate stewardship costs. The 2007 results were also adversely affected by expenses incurred due to liquidated damages and losses from derivative financial instruments.
Revenue and interest of $32.3 million in 2007 increased 167% from 2006 due to a 111% increase in production of crude oil and NGL to 541,069 barrels and a 30% increase in average price received per barrel of oil to $58.79. The increase in production was due primarily to the inclusion of a full year of Colombian and Argentine production and the commencement of production at the beginning of the third quarter of 2007 from two new discovery wells in Colombia. The 2006 production included Colombian production subsequent to Gran Tierra’s acquisition of its Colombian properties in June 2006.
In 2007, operating expenses increased by 147% to $10.5 million, reflecting the inclusion in 2007 of a full year of Colombian and Argentine operating activities for those properties. Commencement of operations for two new discovery wells in Colombia in the third quarter of 2007 also contributed to the increase in operating costs. On a boe basis, operating expenses increased by 18% to $19.31 per boe mainly due to costs associated with budgeted workover projects undertaken to sustain production.
DD&A for the 2007 fiscal year increased by 130% to $9.4 million mainly due to higher production levels. The depletion rate on a boe basis of $17.36 increased by 10% primarily due to a higher proved depletable cost base in Colombia which more than offset the increase in proved reserve levels.
G&A costs for 2007 increased 46% to $10.2 million. The increase in G&A was due to the inclusion of a full year of business activities related to the acquisition of properties in Colombia and additional properties in Argentina. Higher salaries and benefits and stock-based compensation by $2.8 million as well as increased corporate stewardship costs including Sarbanes-Oxley compliance and securities registration related costs accounted for the majority of the increase. Between the two years, G&A per boe declined by 30% to $18.86 per boe reflecting the increase in production which more than offset the incremental G&A expenses contributed by expanded activity levels.
Other expenses of $10.3 million comprised mainly liquidated damages and losses from derivative instruments. Liquidated damages of $7.4 million (2006 - $1.5 million) represent damages payable to stockholders as a result of certain registration statements not becoming effective within the periods specified in the share registration rights agreements for the underlying securities. Financial derivative losses of $3.0 million (2006 - nil) represent losses recorded from a costless collar financial derivative contract of crude oil prices entered into pursuant to the terms and conditions of Gran Tierra’s credit facility.
The income tax expense for 2007 decreased to $0.3 million from $0.7 million in 2006. The Colombian operations generated a net income before tax of $11.5 million in 2007, which resulted in a local income tax liability, offset by a 2007 income tax recovery arising from losses of $2.5 million incurred in Argentina. In Colombia, we used available prior period loss carryforwards and Colombian income tax investment incentives, which permitted additional tax deductions associated with capital investment in producing oil and natural gas properties, to decrease our current income tax otherwise payable. In 2006, the Colombia operations generated income before tax of $1.5 million, which resulted in a local income tax liability of $0.8 million, offset by an income tax recovery of $0.1 million arising from losses incurred in Argentina.
Estimated Proved Oil and Gas Reserves
Estimated proved oil and gas reserves, net of royalties, as of December 31, 2008, were 19.2 million barrels of oil, a 200% increase from the estimated proved reserves as at December 31, 2007. The increase resulted from our successful development drilling program in Colombia which led to new discoveries in Costayaco and Juanambu fields and the addition of crude oil reserves associated with the acquisition of Solana. The new discoveries in Colombia contributed approximately 5 million barrels of oil to our reserve base and the acquisition of Solana contributed approximately 8.5 million barrels of oil.
The estimated proved reserves as at December 31, 2007 of 6.4 million barrels of crude oil, increased by 113% compared with 2006 year-end reserve levels mainly due to the successful development drilling program in the Costayaco field in Colombia.
Segmented Results of Operations
Our operations are carried out in Colombia, Argentina and Peru and we are headquartered in Calgary, Alberta, Canada. Our reportable segments include Colombia, Argentina and Corporate with the latter including the results of our initial activities in Peru. In 2008, Colombia generated 91.4% of our revenues and reflects the operations of Solana for the period from the date of acquisition on November 14, 2008 to December 31, 2008.
Segmented Results of Operations - Colombia
1)
The 2008 results include the operations of Solana subsequent to its acquisition on November 14, 2008.
2)
NGL volumes are converted to boe on a one-to-one basis with oil.
3)
Production represents production volumes adjusted for inventory changes.
Segmented Results of Operations - Colombia for the Year Ended December 31, 2008 compared to the Results for the Year Ended December 31, 2007
For the year ended December 31, 2008, income before income taxes from Colombia amounted to $58.5 million compared to $11.5 million recorded in 2007, primarily the result of increased production of crude oil and higher net realized prices partially offset by increased operating expenses, DD&A and G&A. On a per barrel basis, the pre-tax income for the current year was $53.87 versus $34.47 recorded in the prior year.
In 2008, Production of crude oil and NGL increased by 226% to 1,085,198 barrels compared to 333,157 barrels in 2007. These production levels are after government royalties ranging from 8% to 20% and third party royalties of 2% to 10%.
Gran Tierra’s Colombian operating results for 2008 are principally impacted by new oil production resulting from the success of our 2007 exploration program, undertaken in the first half of 2007, where we made two field discoveries, Costayaco in the Chaza block and Juanambu in the Guayuyaco block. Production from these discoveries commenced in the third quarter of 2007 and has increased during 2008 as the result of development drilling, and with the addition of production from the Costayaco - 2, 3, 4 and 5 wells during the course of 2008.
Our production is also impacted by political and economic factors in Colombia. In the first quarter of 2008, sections of one of the Ecopetrol pipelines were blown up by guerillas, which temporarily reduced our deliveries to Ecopetrol, resulting in higher than average Colombia crude oil inventories at March 31, 2008. Ecopetrol was able to restore deliveries within one to two weeks of these attacks.
On November 24, 2008, we temporarily suspended production operations in the Costayaco and Juanambu oil fields. This was as a result of a declaration of a state of emergency and force majeure by Ecopetrol, due to a general strike in the region where our operations are located, resulting in higher than average Colombia crude oil inventories at December 31, 2008. On January 12, 2009, crude oil transportation resumed in southern Colombia as a result of the lifting of the strike at the Orito facilities operated by Ecopetrol.
The incremental production volumes from Solana properties from the date of acquisition of November 14, 2008 to December 31, 2008 was 69,747 barrels of oil and 14,559 mcf of natural gas, and it was severely impacted by the general strike affecting its two major producing fields of Costayaco and Juanambu.
Revenue and interest were positively impacted by significantly improved net realized crude oil prices. The average net realized prices for crude oil, which are based on WTI prices, increased by 33% to $95.04 per barrel in 2008. The combination of increased production and higher realized prices resulted in our revenue levels from Colombia in 2008 increasing by 335% to $103.2 million.
Operating expenses increased to $12.1 million from $4.1 million last year. The increased operating expenses resulted from the increase in production, inclusion of post-acquisition operating expenses of Solana which amounted to $3.6 million and the increased cost associated with trucking oil from Costayaco to our pipeline. However, the increased production resulted in a reduction of operating expenses on a per barrel basis to $11.16 compared to $12.30 per barrel incurred last year.
For 2008, DD&A increased to $22.2 million from $6.9 million recorded in 2007. Increased production levels coupled with a higher depletable cost base including Solana properties, partially offset by higher reserve levels, accounted for the increase in DD&A. The incremental DD&A recorded as a result of Solana’s acquisition was $6.9 million. Although our Colombian proved reserves increased significantly in 2007 and 2008 as a result of our successful exploration and development activities, we also invested much of our 2007 and 2008 capital spending on the Colombian development program. Our acquisition of Solana in the fourth quarter of 2008 further increased our proved reserves and our depletable cost base. Thus, the increase in DD&A was due to the significant increases in the depletable basis for the fair value of the Solana proved reserves acquired and future capital expenditures associated with the development of the undeveloped proved reserves at December 31, 2008. These future capital expenditures are for further development well drilling and related infrastructure costs to deliver the increased production volumes from Costayaco. On a per boe basis, the DD&A in Colombia for the current year was $20.44, essentially unchanged from 2007 due to the significant increase in proved reserves offsetting the impact of a higher depletable cost pool.
Higher management and administrative expenses incurred to manage the increased level of development and operating activities resulting from the successful 2007 exploration and 2008 development activities resulted in G&A expense increasing to $4.8 million in 2008 from $1.7 million incurred in 2007. On a per barrel basis, the G&A expense decreased by 14% to $4.39 for the current year.
Other items in 2008 include a foreign exchange loss of $6.6 million which primarily resulted from the translation of a deferred tax liability recognized on the purchase of Solana. This deferred tax liability, a monetary liability, is denominated in the local currency of the Colombian foreign operations and as a result, a foreign exchange loss has been calculated on conversion to the US dollar functional currency.
Segmented Results of Operations - Colombia for the Year Ended December 31, 2007 compared to the Results for the Year Ended December 31, 2006
Increased production levels in 2007 as well as higher realized crude oil prices increased income before income taxes in Colombia by 673% to $11.5 million from $1.5 million in 2006. The improvement in revenue was partially offset by higher costs resulting from expanded activity levels. On a per barrel basis, income before income taxes tripled to $34.47 per boe compared to 2006.
Crude oil and NGL production, after government royalties ranging from 8% to 20% and a third party 2% overriding royalty, increased by 158% to 333,157 barrels in 2007. The increase in production was due primarily to the inclusion of a full year of Colombian production and the commencement of production at the beginning of the third quarter from the two new discovery wells, one in the Juanambu area of the Guayuyaco block and the other in the Costayaco area of the Chaza block. The 2006 production consisted solely of Colombian production subsequent to Gran Tierra’s entry into Colombia through the acquisition of Argosy in June 2006.
Crude oil and NGL revenue, net of royalties, for 2007 increased to $23.7 million, or $71.28 per barrel, compared to $6.6 million, or $51.17 per barrel, for 2006. In addition to the increase in production resulting from the new discovery wells and a full year of production from the other areas, revenue increased due to the higher WTI crude oil price in 2007.
A full year of Colombian operating activities and the commencement of operations of the new discovery wells at Juanambu and Costayaco in the third quarter of 2007 resulted in a 195% increase in operating expenses to $4.1 million in 2007. On a per boe basis the operating costs increased by 15% to $12.30 per boe due to the inclusion of budgeted workover expense carried out mainly in the Guayuyaco block.
In 2007, DD&A increased 175% to $6.9 million primarily due to the increase in production over the prior year. Gran Tierra invested much of its 2007 capital spending on the Colombia exploration program resulting in a significant increase in the Colombian depletable cost pool. However, the effect of this on depletion was mostly offset by a significant increase in our proved reserves. As a result, our depletion rate increased only by 7% to $20.56 per boe as compared to $19.30 per boe for 2006.
G&A for 2007 increased to $1.7 million from $0.9 incurred in 2006 due to the inclusion of a full year of business activities related to the acquisition of the Argosy properties in Colombia. In 2006, G&A included expenses incurred from the date of acquisition of Argosy on June 21, 2006 to the end of the year.
Capital Program - Colombia
Gran Tierra’s focus in 2008 was to develop the Costayaco field to increase our production and reserves, in addition to undertaking additional oil exploration efforts to further define the potential of our acreage in Colombia. In support of this strategy, our capital expenditures in Colombia amounted to $31.7 million in 2008. Included in this amount was $6.8 million in capital expenditures related to the Solana properties subsequent to the acquisition.
During 2008, we drilled five development wells in the Costayaco field for a net cost of $17.8 million: Costayaco-2, which had commenced drilling in December 2007, and Costayaco-3, -4, -5 and -6. Four of these wells, Costayaco-2,-3, -4, and -5 were tested, completed and brought on production in 2008. Costayaco-6 was testing at year end. We also completed a 15-km 8-inch pipeline to connect the Costayaco field to our existing pipeline infrastructure for a net cost of $4.0 million.
In 2008, we also spent $9.9 million on activities on our other blocks including:
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Guayuyaco - We carried out two workovers on the Juanambu-1 producing well.
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Rio Magdalena - We drilled Popa-2 well, which encountered natural gas and natural gas liquids. This well was fully funded by our partners as part of our farm-in agreement.
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Santana - We carried out remedial work on various wells and changed the artificial lift system on one well in the Miraflor field, adding incremental production.
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Mecaya - We acquired 15km of 2D seismic.
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Azar - We acquired 40 square kilometers of 3D seismic and we performed one well re-entry on the Palmera 1 well, encountering oil.
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Guachiria Norte Block - We drilled an exploration well, Zafiro-1, in November 2008, which was dry.
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Putumayo A&B Technical Evaluation Areas - We conducted 400 kilometers of seismic reprocessing and geologic studies.
The main expenditure of Solana after the acquisition related to the completion of the drilling of the Zafiro -1 well in the Guachiria Norte Block.
During the year ended December 31, 2007, we spent $14.2 million on capital projects. Our focus in 2007 was on exploration drilling and we drilled six wells during the year. We drilled successful wells in the Chaza and Guayuyaco areas and in March 2007 we drilled the Juanambu-1 well and encountered hydrocarbon shows in four zones. Testing established the presence of a significant oil accumulation. We drilled and tested the Costayaco-1 well, which also indicated a significant accumulation of oil in a number of zones. Consequently, our proven reserves in Colombia substantially increased. We put these wells on production in the third quarter of 2007. We drilled the Juanambu-1 and Costayaco-1 wells and commenced drilling of Costayaco-2 for a net cost of $7.6 million.
We drilled four exploration wells in 2007 comprising the Laura-1 exploration well in the Talora Block in January 2007, the Caneyes-1 exploration well in the Rio Magdalena Block in February 2007, and the Soyona-1 and Cachapa-1 exploration wells in the Primavera Block in April and March 2007, respectively. These wells were plugged and abandoned. We drilled the Caneyes-1 well at a net cost to us of $1.7 million and the drilling costs for the three other wells were paid by our partners.
During 2007, we incurred costs of $4.9 million on other projects including $1.7 million for completion of a 3-D seismic program in Costayaco to optimize positioning of future drilling locations and $1.2 million related to a 2-D seismic program in the Rio Magdalena block. We also relinquished ownership of the Primavera block which was acquired as part of Argosy transaction in 2006 and acquired the Putumayo A and B technical evaluation areas.
Capital expenditures for the year ended December 31, 2006 were $47.2 million and were mainly comprised of the acquisition of Argosy. Prior to June 20, 2006, we did not own any oil or gas properties in Colombia. On June 20, 2006, we acquired Argosy and became the operator of nine blocks in Colombia. The Santana, Guayuyaco and Chaza blocks are currently producing. The Rio Magdalena, Talora, Azar and Mecaya blocks are in their exploration phases.
Segmented Results of Operations - Argentina
(1) Gas volumes are converted to boe at the rate of 20 mcf of gas per barrel of oil based upon the approximate relative values of natural gas and oil. NGL volumes are converted to boe on a one-to-one basis with oil.
(2) Production represents production volumes adjusted for inventory changes.
For the 2008 fiscal year, the results from the Argentina reflected a pre-tax loss of $3.2 million compared to pre-tax losses of $2.5 million and $0.4 million recorded in fiscal years 2007 and 2006, respectively, due to higher expenses associated with expanded activities which have more than offset the effect of production increases.
Crude oil and NGL production, after 12% royalties, increased to 242,947 barrels in 2008 compared to 207,912 barrels in 2007 and 127,712 barrels in 2006. The increase resulted from the successful completion and testing of Proa - 1 exploration well in the Surubi block in the third quarter of 2008 with sales commencing in the fourth quarter as well as the commencement of a full year of Argentine production in 2007 following property acquisitions made in 2006. Commencing in 2008, natural gas production is used for operating power generation with any excess production sold in the market.
Due to the local regulatory regimes, the average realized price for crude oil and NGL in Argentina for the past three years has been just under $40 per barrel. Currently, the price we receive for production from our Surubi block is $40 per barrel and it is $33 per barrel for production from other areas. Furthermore, currently all oil and gas producers in Argentina are operating without sales contracts. A new withholding tax regime was introduced in Argentina without specific guidance as to its application. Producers and refiners of oil in Argentina have been unable to determine an agreed sales price for oil deliveries to refineries. Along with most other oil producers in Argentina we are continuing deliveries to the refineries and are negotiating a price for deliveries made after December 31, 2008. The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced by the lower sales price. We are working with other oil and gas producers in the area, as well as Refiner S.A. and provincial governments, to lobby the federal government for change.
With regulated crude oil prices, the change in our revenues over the three-year period has been reflective of changes in our production levels. Revenues of $9.6 million generated in 2008 compare to $8.1 million in 2007 and $5.1 million in 2006.
The increase in total expenses year-over-year was also attributable to higher production levels as well as expanded operations. Operating expenses remained fairly constant on a boe basis between 2008 and 2007 but reflected higher workover costs in 2007 compared with 2006. Likewise, the increase in DD&A over the three-year period was attributable to higher production levels, increased depletable cost pools, offset partially by additional proved reserves. Increases in stock-based compensation, higher consulting costs associated with the expanded operations and the need for increased administration staff and professional costs associated with properties purchased late in 2006 contributed to the increase in G&A expenses over the three-year period. On a per boe basis, the G&A stayed fairly constant at just under $9.
Capital Program - Argentina
Capital expenditures for the year ended December 31, 2008, amounted to $11.7 million and included drilling of the Proa-1 discovery well on the Surubi block for a net cost of $9.5 million. Proa-1 commenced production in September 2008. The provincial oil company REFSA farmed-in to the block for a 15% working interest, and are paying their share of well costs from their share of production from Proa-1. In 2008, other costs of $1.2 million were incurred primarily on capitalized well workovers, well re-entries, seismic acquisition, and equipment upgrades.
In 2007, we spent $1.7 million including costs of $0.7 million for the completion of the Puesto Climaco-2 sidetrack well in the Vinalar Block which was drilled in December 2006. Capital expenditures also included the acquisition and reprocessing of seismic in several areas and facility upgrades in Parma Largo.
In 2006, Capital expenditures were $14.1 million and were primarily related to the purchase of the El Vinalar and CGC properties, development activity at Palmar Largo, and purchase of office equipment and leasehold improvements.
Segmented Results of Operations - Corporate
Segmented Results of Operations - Corporate
In addition to the expenditures associated with the maintenance of Gran Tierra’s headquarters in Calgary, Alberta, Canada, and cost of compliance and reporting under the securities regulation, the results of the Corporate Segment include the results of our initial operations in Peru.
G&A Expenses
The increase in G&A expenses over the three-year period was due to higher corporate stewardship costs including Sarbanes-Oxley compliance requirements, securities exchange listing fees in both Canada and the United States, costs related to securities registration and higher stock-based compensation expense due to increased option grants.
Liquidated Damages
Liquidated damages of $7.4 million in fiscal year 2007 relate to liquidated damages payable to Gran Tierra’s stockholders as a result of the registration statement for 50 million units sold in the second quarter of 2006 not becoming effective within the period specified in the share registration rights agreements for those securities. This registration statement became effective on May 14, 2007 and no additional liquidated damages were incurred after that time.
Liquidated damages of $1.5 million recorded in 2006 relate to liquidated damages payable to Gran Tierra’s stockholders as a result of the registration statements for our securities issued in 2005 and 2006 not becoming effective within the periods specified in the share registration rights agreements for those securities. The amount expensed includes $0.3 million related to 15,047,606 units issued in the fourth quarter of 2005 and first quarter of 2006 and $1.3 million related to 50 million units sold in the second quarter of 2006. We did not have any liquidated damages in 2005.
On June 27, 2007, under the terms of the Registration Rights Agreements, we obtained a sufficient number of consents from the signatories to the agreements waiving our obligation to pay in cash the accrued liquidated damages. We agreed to amend the terms of the warrants issued in the 2006 offering by reducing the exercise price of the warrants from $1.75 to $1.05 and extending the life of the warrants by one year. The amendment to the terms of the warrants was reflected as an increase of $8.6 million in the value of warrants recorded on the consolidated balance sheet and expensed as liquidated damages in the results of operations.
Loss (Gain) from Derivative Financial Instruments
In accordance with the terms of the credit facility with Standard Bank Plc, in February of 2007 we entered into a costless collar financial derivative contract for crude oil based on WTI price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010.
For the year ended December 31, 2008, we recorded a gain of $0.2 million due to the significant decrease in WTI crude oil price experienced in the second half of 2008. For the year ended December 31, 2007, we recorded a loss of $3.0 million due to the significant increase in WTI crude oil price experienced throughout 2007.
Foreign Exchange Loss (Gain)
The foreign exchange loss (gain) results from the translation of foreign currency denominated transactions to US Dollars.
Capital Program - Corporate
The 2008 capital expenditures of $3.3 million for the Corporate Segment included expenditures of $2.8 million for Peru on our exploration blocks 122 and 128. Acquisition of technical data through aeromagnetic-gravity studies began in 2007, and was completed in the first half of 2008, with a total of 20,000 kilometers of data acquired over both blocks. In 2008, we started Environmental Impact Assessments and the community consultation process on both blocks. These projects will be completed in 2009, along with drilling feasibility and geological studies.
In 2007, capital expenditures of $0.7 million were primarily related to Peru and included technical studies of Block 122 and Block 128 and the initiation of an aero magnetic and gravity survey over both blocks. This program commenced in the fourth quarter of 2007 and was completed in 2008.
We acquired Block 122 and Block 128 in the fourth quarter of 2006 and expenditures in Peru were minimal in 2006.
Fourth Quarter Results
The following table provides an analysis of quarterly financial information (in thousands of dollars except per share amounts) for the three months ended December 31, 2008 compared to the same period in 2007:
For the three months ended December 31, 2008, Gran Tierra recorded a loss of $12.7 million ($0.07 per share) compared to net income of $2.2 million ($0.02 per share) recorded in the same period last year. The fourth quarter results were adversely affected by the sharp decline of crude oil prices, temporary suspension of production in two major producing fields in Colombia, and the consolidation of Solana expenses effective November 14, 2008 including the amortization of the purchase price adjustment recorded for the fair value of the Solana assets and a foreign exchange loss of $8.1 million mainly resulting from the translation of a deferred tax liability recognized on the purchase of Solana. Furthermore, incremental revenues contributed by Solana were marginal due to the suspension of the production in the fields which represent Solana’s major producing properties.
Production of crude oil increased by 72% to 4,074 barrels per day from 2,371 barrels per day in the last quarter of 2007. The positive effect of this increase in production was offset by the sharp decline in crude oil prices. Average prices per barrel of oil declined by 31% to $50.49 from $72.93 realized in the same quarter last year. The fourth quarter production levels in 2008 were also adversely impacted by the temporary suspension of production operations in the Costayaco and Juanambu oil fields on November 24, 2008. This was as a result of a declaration of a state of emergency and force majeure by Ecopetrol, due to a general strike in the Putumayo region where our Costayaco field and our Guayuyaco and Santana producing blocks are located. On January 12, 2009, crude oil transportation resumed in southern Colombia as a result of the lifting of the strike at the Orito facilities operated by Ecopetrol. The suspension also negatively affected the expected incremental contribution of production from Solana’s interest in the Costayaco field.
The increase in expenses between the two quarters was associated with the expanded activities of Gran Tierra as well as the additional Solana expenses recorded subsequent to the acquisition of Solana on November 14, 2008. During the shutdown, we incurred costs of maintaining and servicing the facilities acquired from Solana. DD&A expense between the two quarters also increased significantly due to higher production levels and the increased depletion base resulting from recording the fair values of property, plant and equipment acquired from Solana.
Liquidity and Capital Resources
At December 31, 2008, we had cash and cash equivalents of $176.8 million compared to $18.2 million at December 31, 2007 and $24.1 million at December 31, 2006. We believe that our cash position together with our positive cash flow from operations and access to unutilized credit facilities with a borrowing base of $33 million and no debt will provide us with sufficient liquidity to meet our strategic objectives and fund our planned capital program over the course of 2009 and in the near future. In accordance with Gran Tierra’s investment policy, cash balances are invested only in United States or Canadian government backed federal, provincial or state securities with the highest credit ratings and short term liquidity.
Effective February 22, 2007, we entered into a revolving credit facility with Standard Bank Plc. The facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of our petroleum reserves of our subsidiary, Gran Tierra Energy Colombia Ltd., up to maximum of $50 million. The initial borrowing base was $7 million based on mid-2006 reserves and it can be re-determined semi-annually based on reserve evaluation reports. As a result of Standard Bank Plc’s review of our mid-year 2007 independent reserve audit, we have received preliminary approval to increase our borrowing base to $20 million; however, we have not pursued this further as the additional credit is not required at this time. The facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base. The facility is secured primarily by the assets of our subsidiary, Gran Tierra Energy Colombia Ltd. Under the terms of the facility, we are required to maintain compliance with specified financial and operating covenants. As at December 31, 2008, Gran Tierra was in full compliance with these terms and conditions. We were required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the aggregate net share of Colombian production after royalties for the three-year term of the facility as projected by September 30, 2006 Independent Reserve Evaluation Report. As of December 31, 2008, no amounts have been drawn-down under this facility.
We acquired Solana, effective November 14, 2008, which has a credit facility with BNP Paribas. The facility has a maturity date of December 20, 2010 and may be extended by agreement between the parties. The borrowing base is currently $26 million, based on the current value of our petroleum reserves of our subsidiary, Solana Petroleum Exploration (Colombia) Ltd., up to a maximum of $100 million. The facility includes a letter of credit sublimit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus a margin for each quarter dependent on production for the previous quarter as follows: 3.125% for production less than 1,500 barrels of oil per day; 2.875% for production between 1,500 and 3,000 barrels of oil per day; 2.625% for production between 3,000 and 5,000 barrels of oil per day; and 2.375% for production over 5,000 barrels of oil per day. The facility is secured primarily by the assets of Solana Petroleum Exploration (Colombia) Ltd. Under the terms of the facility, we are required to maintain compliance with specified financial and operating covenants. As of December 31, 2008, no amounts have been drawn-down under this facility.
Both Standard Bank Plc and BNP Paribas have provided consent letters with regard to our acquisition of Solana. The letters of consent provided by the banks each contain a number of conditions which effectively limit the time period of the consent to 150 days from the acquisition date of November 14, 2008. We are currently working with both banks to determine the appropriate facility going forward.
The following provides an analysis of our cash in-flows and out-flows during the three-year period ended December 31, 2008:
Cash Flows during the Year Ended December 31, 2008
During the year ended December 31, 2008, our cash and cash equivalents increased by $158.6 million due to positive cash inflows from operations of $109.7 million, from investing activities of $27.1 million and from financing activities of $21.7 million. Net cash provided by operating activities was positively affected by the significant increases in crude oil production and prices as well as collection of receivables assumed as part of the Solana acquisition and an increase in current income taxes payable related to Gran Tierra’s taxable position in Colombia.
Cash inflows from investing activities include $81.9 million assumed on the purchase of Solana, net of acquisition costs, offset by $55.2 million in capital expenditures related to our exploration and development and other oilfield related activities, net of the change in non-cash working capital. Cash inflows from financing activities of $21.7 million related to the proceeds from the exercise of warrants and stock options.
Cash Flows during the Year Ended December 31, 2007
During the year ended December 31, 2007, our cash and cash equivalents declined by $5.9 million as a positive cash contribution from operations of $8.8 million was more than offset by funds of $16.0 million (net of changes in non-cash working capital related to capital expenditures) expended in our capital expenditure program relating to our drilling and other oilfield activities primarily in Colombia. Also, the restricted funds of $1.0 million related to the 2006 escrow agreement were released to our treasury.
Cash Flows during the Year Ended December 31, 2006
During the year ended December 31, 2006, our cash and cash equivalents increased by $21.9 million to $24.1 million. A positive contribution from operations of $2.0 million, coupled with $68.1 million raised through financing activities, was partially utilized for investing activities of $48.3 million.
The investing activities comprised $36.9 million related to the purchase of Argosy and $10.3 million (net of changes in non-cash working capital related to capital expenditures) used for our capital expenditure program relating to drilling activities in Colombia, the purchase and development of properties in Argentina, and office equipment and leasehold improvements in both Calgary and Argentina.
Our financing activities comprised proceeds from a series of private placements of securities including $75.0 million, less issue costs of $6.3 million, from the sale of 50 million units of our securities at a price of $1.50 per unit pursuant to four separate Securities Purchase Agreements in June 2006 (“2006 Offering”), $0.6 million from the sale of 762,500 units of our securities in the first quarter of 2006, and proceeds from the exercise of warrants to purchase common stock. However, of the amount raised under the 2006 Offering, $1.3 million was held in escrow at December 31, 2006, and the holders of those units had the right to return the units to us and receive their purchase price back under the terms of the escrow agreement because we were unable to obtain a securities laws exemption for those holders by a specified date. Each unit of securities issued under the 2006 Offering comprised one share of Gran Tierra’s common stock and one warrant to purchase one-half of a share of Gran Tierra’s common stock at an exercise price of $1.75 for period of five years. In connection with the issuance of these securities, Gran Tierra entered into four separate Registration Rights Agreements with the investors pursuant to which Gran Tierra agreed to register for resale the shares and warrants (and shares issuable pursuant to the warrants) issued to the investors in the offering by November 17, 2006, and if we failed to do so we would be obligated to pay liquidated damages. For a further discussion of liquidated damages, reference should be made to the discussion and analysis appearing under the caption “Segmented Results of Operations - Corporate” appearing on page 65 of this Report.
Off-Balance Sheet Arrangements
As at December 31, 2008, 2007 and 2006, we had no off-balance sheet arrangements.
Contractual Obligations
Gran Tierra holds three categories of operating leases namely office, vehicle and housing. We pay monthly costs of $141,998 for office leases, $15,338 for vehicle leases, $9,400 for a compressor and $5,567 for certain employee accommodation leases in Colombia.
Future lease payments and other contractual obligations at December 31, 2008 are as follows:
Related Party Transactions
In connection with the Solana acquisition, we acquired additional office space of 4,441 square feet used by Solana as its headquarters in Calgary. The lease payments under the lease are $8,975 per month and operating and other expenses are approximately $4,000 per month. The lease expires on April 30, 2014. On February 1, 2009, we entered into a sublease for that office space with a company, of which two of Gran Tierra’s directors are shareholders and directors. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $7,050 per month plus approximately $4,000 for operating and other expenses. The terms of the sublease are consistent with current market conditions in the Calgary real estate market.
Outlook
Business Environment
Our revenues have been negatively impacted by the recent decline in crude oil prices. Crude oil prices are volatile and unpredictable and are influenced by concerns about financial markets and the expected adverse impact of the slowing worldwide economy on oil demand growth. However, based on projected production, prices, costs and our current liquidity position, we believe that our current operations and capital expenditure program can be maintained from cash flow from existing operations, cash on hand, and our credit facilities, barring unforeseen events or a further severe downturn in oil and gas prices. Should our operating cash flow decline, we would examine measures such as reducing our capital expenditure program, issuance of debt, or issuance of equity.
The credit markets, including the commercial paper markets in the United States, have recently experienced adverse conditions. Although we have not been materially impacted by these conditions, continuing volatility in the credit markets may increase costs associated with renewing or increasing our credit facilities, or affect our, or third parties we seek to do business with, ability to access those markets.
Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt markets. Increases in the borrowing base under our credit facilities are dependent on our success in increasing oil and gas reserves and on future oil prices. Additional funds will be provided to us if holders of our warrants to purchase common shares decide to exercise the warrants. Should we be required to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing stockholders, and this dilution would be exacerbated by a decline in our stock price. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets that are not currently pledged under our existing credit facilities.
Work Program and Capital Expenditure Program
Gran Tierra’s 2009 work program is intended to create both growth and value in our existing assets through increasing our reserves and production, while retaining the financial flexibility, with a strong cash position and no debt, to pursue acquisition opportunities.
We are seeking to grow production to approximately 20,000 barrels of oil per day, net after royalty, in the second half of 2009, with 19,000 barrels from Colombia and 1,000 barrels from Argentina.
We anticipate the existing pipeline system connecting the Costayaco field to the Orito gathering facilities can accommodate an estimated 15,000 barrels of oil per day gross production from the Costayaco field with new pumps, in addition to crude oil from the other existing producing fields. Trucking capacity can handle an additional 10,000 barrels of oil per day capacity from the Costayaco field. This would accommodate a growth in 2009 production from Costayaco to an estimated 25,000 barrels of oil per day gross in the second half of 2009.
Gran Tierra has planned a 2009 capital spending program of $198 million for exploration and development activities in Colombia, Peru, and Argentina. Planned capital expenditures in Colombia are $178 million, $10 million in Peru, and $10 million in Argentina.
We expect that our committed and discretionary 2009 capital program can be funded from cash flow from operations if WTI oil price averages above $61 per barrel of oil for 2009. If WIT oil price averages between $22 per barrel and $61 per barrel for 2009 we expect to be able to fund these programs from cash flow from operations plus available cash balances.
We will continue to monitor our capital spending during 2009. We have the flexibility to defer or cancel portions of our capital program in response to a drop in WTI from the current levels of approximately $36 to $45 per barrel of oil.
Outlook - Colombia
The bulk of 2009 capital spending in Colombia is scheduled to be dedicated to further developing the Costayaco field in the Chaza block. Four additional development wells are planned, Costayaco-7 through 10. In addition, one water injector well is scheduled to be drilled and three existing well workovers undertaken. New infrastructure construction is planned to continue, including support facilities, crude oil gathering lines, water lines, two pumping stations and storage batteries.
In addition to the ongoing Costayaco field development activities, we plan to carry out an active exploration and development program on our other blocks in Colombia, including:
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Drilling a development well, Juanambu-2, in the Guayuyaco block.
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Drilling one exploration well in each of the Chaza, Azar, Mecaya, Rio Magdalena, San Pablo and Catguas blocks.
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Acquiring up to 665 kilometers of seismic.
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Long term production tests on the Palmera-1 heavy oil discovery in the Azar block and the Popa-2 gas-condensate discovery in the Rio Magdalena block.
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Upgrades to facilities.
During 2009, we expect portions of the Putumayo West A Technical Evaluation Area to be converted to one or more ANH exploration contracts with new seismic acquisition program commitments in 2009. In addition, we expect a portion of the Putumayo West B Technical Evaluation Area to be converted to an exploration license, also with a new seismic acquisition program commitment for 2009.
Outlook - Argentina
Gran Tierra’s planned work program for 2009 consists of conducting nine workovers of existing producing wells, facilities upgrades, and 162 Km2 of 3-D seismic acquisition in the Chivil and Surubi Blocks.
Outlook - Peru
We have entered the second exploration period of both blocks 122 and 128 on the eastern flank of the Marañon Basin of northern Peru. We have identified 24 leads based on interpretation of a 20,000 linear kilometer airborne gravity and magnetic survey completed over the blocks in 2008. An environmental impact survey is currently being undertaken in preparation for a 500 kilometer 2-D seismic survey expected to be acquired in the fourth quarter of 2009 and into the first quarter of 2010 over the principal leads identified on the two blocks. We expect exploration drilling to take place in the second half of 2010. In addition, a pre-feasibility engineering field development study is scheduled to be undertaken during 2009 to assist with early planning in the event a commercial discovery is made in 2010.
Critical Accounting Policies and Estimates
The preparation of financial statements under generally accepted accounting principles (“GAAP”) in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regards to estimates used. We believe that the assumptions, judgments and estimates involved in the accounting for oil and gas accounting and reserves determination, establishment of fair values of assets and liabilities acquired as part of acquisitions, impairment, asset retirement obligations, goodwill impairment, deferred income taxes, share-based payment arrangements, and warrants have the greatest potential impact on our consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting estimates. Our critical accounting policies and significant judgments and estimates related to those policies are discussed below.
Actual results could differ from these estimates, however, historically, our assumptions, judgments and estimates relative to our critical accounting estimates have not differed materially from actual results.
On a regular basis we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.
Oil and Gas Accounting Reserves Determination
We follow the full cost method of accounting for our investment in oil and natural gas properties, as defined by the SEC, as described in note 2 to our annual consolidated financial statements. Full cost accounting depends on the estimated reserves we believe are recoverable from our oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data.
To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including:
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Expected reservoir characteristics based on geological, geophysical and engineering assessments
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Future production rates based on historical performance and expected future operating and investment activities
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Future oil and gas quality differentials
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Assumed effects of regulation by governmental agencies
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Future development and operating costs
We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are audited at least annually by independent qualified reserves consultants.
Our Board of Directors oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.
Reserves estimates are critical to many of our accounting estimates, including:
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Determining whether or not an exploratory well has found economically producible reserves
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Calculating our unit-of-production depletion rates. Proved reserves estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense.
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Assessing, when necessary, our oil and gas assets for impairment. Estimated future cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.
Oil and Gas Accounting and Impairment
The accounting for and disclosure of oil and gas producing activities requires that we choose between GAAP alternatives. We use the full cost method of accounting for our oil and natural gas operations. Under this method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of proved reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.
Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter on a country-by-country basis. The ceiling limits these pooled costs to the aggregate of the after-tax, present value, discounted at 10%, of future cash flows attributable to proved reserves, known as the standardized measure, plus the lower of cost or market value of unproved properties less any associated tax effects. Cash flow estimates for our impairment assessments require assumptions about two primary elements - constant prices and reserves. It is difficult to determine and assess the impact of a decrease in our proved reserves on our impairment tests. The relationship between the reserves estimate and the estimated discounted cash flows is complex because of the necessary assumptions that need to be made regarding period end production rates, period end prices and costs. If these capitalized costs exceed the ceiling, we will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expense in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling. Due to the complexity of the calculation, we are unable to provide a reasonable sensitivity analysis of the impact that a reserves estimate decrease would have on our assessment of impairment. A reduction in oil and natural gas prices and/or estimated quantities of oil and natural gas reserves would reduce the ceiling limitation and could result in a ceiling test write-down.
We assessed our oil and gas properties for impairment as at December 31, 2008, 2007 and 2006 and found no impairment write-downs were required based on our assumptions. Estimates of standardized measure of our future cash flows from proved reserves were based on realized crude oil prices of $44.60 in Colombia and $40 for oil production from the Surubi block in Argentina and $33 for production from all other blocks in Argentina as at December 31, 2008.
The acquisition of Solana, effective November 14, 2008, was accounted for using the purchase method, with Gran Tierra being the acquirer, whereby the Solana assets acquired and liabilities assumed were recorded at their fair values at the acquisition date with the excess of the purchase price over the fair values of the tangible and intangible net assets acquired recorded as goodwill. Calculation of fair values of assets and liabilities, which was done by independent advisors, is subject to estimates which include various assumptions including the extent of proved and unproved reserves of the acquired company as well as the future production and development costs and the future oil and gas prices.
While these estimates of fair value for the various assets acquired and liabilities assumed have no effect on our liquidity or capital resources, they can have an effect on the future results of operations. Generally, the higher the fair value assigned to both oil and gas properties and non-oil and gas properties, the lower future net income will be as a result of higher future depreciation, depletion and accretion expense. Also, a higher fair value assigned to the oil and gas properties, based on higher future estimates of oil and gas prices, will increase the likelihood of a full cost ceiling write down in the event that subsequent oil and gas prices drop below our price forecast that was used to originally determine fair value.
Asset Retirement Obligations
We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future asset retirement obligations requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.
We record asset retirement obligations in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and expected changes in legal, regulatory, environmental and political environments. The asset retirement obligations result in an increase to the carrying cost of our property, plant and equipment. The obligations are accreted with the passage of time. A change in any one of our assumptions could impact our asset retirement obligations, our property, plant and equipment and our net income.
It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.
Goodwill
Goodwill represents the excess of purchase price of business combinations over the fair value of net assets acquired and we test for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. We estimate the fair value of each reporting unit and compare it to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, we write down the goodwill to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for our reporting units, we estimate the fair values of the reporting units based upon estimated future cash flows of the reporting unit. The goodwill on our financial statements was a result of the Solana and Argosy acquisitions, and relates entirely to the Colombia reporting segment.
Deferred Income Taxes
We follow the liability method of accounting for income taxes whereby we recognize deferred income tax assets and liabilities based on temporary differences in reported amounts for financial statement and tax purposes. We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.
To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.
Share-Based Payment Arrangements
We record share-based payment arrangements in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised), “Share-Based Payment”, which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options based on estimated fair values.
SFAS 123R requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations.
Under SFAS 123R, share-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Compensation expense is recognized using the accelerated method. As share-based compensation expense recognized in the Consolidated Statements of Operations is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates.
Under SFAS 123R, we utilized a Black-Scholes option pricing model to measure the fair value of stock options granted to employees. Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, our expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors.
Option-pricing models were developed for use in estimating the value of traded options that have no vesting or hedging restrictions and are fully transferable. Because (1) our employee stock options have certain characteristics that are significantly different from traded options, and (2) changes in the subjective assumptions can materially affect the estimated value, in management’s opinion, the existing valuation models may not provide an accurate measure of the fair value of our employee stock options. Although the fair value of employee stock options is determined in accordance with SFAS No. 123R, using a Black-Scholes option-pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. We are responsible for determining the assumptions used in estimating the fair value of its share-based payment awards.
Warrants
We follow the fair-value method of accounting for warrants issued to purchase our common stock. The change of $8.6 million in the fair value of warrants issued in the 2006 Offering, arising from the amendment to the terms of the warrants in connection with the settlement of the liability for liquidated damages, was determined using a Black-Scholes warrant pricing model based on a 25% volatility rate, which reflects a typical volatility rate used to value this type of financial instrument.
New Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value under US GAAP and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 157-2 which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. These nonfinancial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test, asset retirement obligations and nonfinancial assets acquired and liabilities assumed in a business combination. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. Effective January 1, 2008, Gran Tierra adopted SFAS 157 for financial assets and liabilities. The partial adoption of SFAS 157 for financial assets and liabilities did not have a material impact on Gran Tierra’s consolidated financial position, results of operations or cash flows. Beginning January 1, 2009, Gran Tierra will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, nonfinancial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. Gran Tierra does not expect the provisions of SFAS 157 related to these items to have a material impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS 159 permits an entity to elect fair value as the initial and subsequent measurement attribute for many financial assets and liabilities. Entities electing the fair value option would be required to recognize changes in fair value in earnings. Entities electing the fair value option are required to distinguish on the face of the consolidated balance sheet, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. The adoption of SFAS 159 on January 1, 2008 did not impact Gran Tierra’s consolidated financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141 (R), “Business Combinations”, and SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS 141 (R) requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141 (R) and SFAS 160 are effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited and the provisions are applied prospectively. The adoption of these statements is not expected to have a material effect on Gran Tierra’s consolidated financial statements but these changes may affect potential future business combinations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”. SFAS 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and how derivative instruments and related hedged items affect a company's financial position, financial performance and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of this statement is not expected to have a material effect on Gran Tierra’s consolidated financial statements.
In April 2008, the FASB issued FSP 142-3, “Determination of the Useful Life of Intangible Assets”. FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited. The adoption of this statement is not expected to have a material impact on Gran Tierra’s consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. It is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. The adoption of this statement is not expected to have a material effect Gran Tierra’s consolidated financial statements.
In June 2008, the FASB ratified the consensus reached on EITF 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”. EITF 07-05 clarifies the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which would qualify as a scope exception under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”. EITF 07-05 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption for an existing instrument is not permitted. The adoption of this EITF is not expected to have a material effect on Gran Tierra’s consolidated financial statements.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling is effective for disclosures in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2009. Early adoption is not permitted. Gran Tierra is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Our principal market risk relates to oil prices. We have not hedged these risks in the past. Essentially 100% of our revenues are from oil sales at prices which are defined by contract relative to West Texas Intermediate and adjusted for transportation and quality, for each month. In Argentina, a further discount factor which is related to a tax on oil exports establishes a common pricing mechanism for all oil produced in the country, regardless of its destination.
In accordance with the terms of the credit facility with Standard Bank Plc, which we entered into on February 28, 2007, we entered into a costless collar financial derivative contract for crude oil based on West Texas Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. At December 31, 2008, the value of this costless collar was $233,000 . A hypothetical 10% increase in WTI price on December 31, 2008 would cause the value to decrease by approximately $229,000, and a hypothetical 10% decrease in WTI price on December 31, 2008 would cause the value to increase by approximately $345,000.
We consider our exposure to interest rate risk to be immaterial. Interest rate exposures relate entirely to our investment portfolio, as we do not have short-term or long-term debt. However, if we draw down amounts under our credit facilities with Standard Bank Plc or BNP Paribas, we will incur interest rate risk with respect to the amounts drawn down and outstanding. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates, or government securities of the United States or Canadian federal governments such as Guaranteed Investment Certificates or Treasury Bills. We do not hold any of these investments for trading purposes. We do not hold equity investments.
Foreign currency risk is a factor for our company but is ameliorated to a large degree by the nature of expenditures and revenues in the countries where we operate. We have not engaged in any formal hedging activity with regard to foreign currency risk. Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. price of West Texas intermediate oil. In Colombia, we receive 75% of oil revenues in U.S. dollars and 25% in Colombian pesos at current exchange rates. The majority of our capital expenditures in Colombia are in U.S. dollars and the majority of local office costs are in local currency. As a result, the 75%/25% allocation between U.S. dollar and peso denominated revenues is approximately balanced between U.S. and peso expenditures, providing a natural currency hedge. In Argentina, reference prices for oil are in U.S. dollars and revenues are received in Argentine pesos according to current exchange rates. The majority of capital expenditures within Argentina have been in U.S. dollars with local office costs generally in pesos. While we operate in South America exclusively, the majority of our spending since our inauguration has been for acquisitions. The majority of these acquisition expenditures have been valued and paid in U.S. dollars.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Chartered Accountants
To the Board of Directors and Shareholders of Gran Tierra Energy Inc.
We have audited the accompanying consolidated balance sheets of Gran Tierra Energy Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations and retained earnings (accumulated deficit), shareholders' equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Gran Tierra Energy Inc. and subsidiaries as at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as at December 31, 2008, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009, expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Canada
February 24, 2009
Gran Tierra Energy Inc.
Consolidated Statements of Operations and Retained Earnings (Accumulated Deficit)
For the Years ended December 31, 2008, 2007 and 2006
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Balance Sheets
As at December 31, 2008 and 2007
(Thousands of U.S. Dollars)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Cash Flow
For the Years ended December 31, 2008, 2007 and 2006
(Thousands of U.S. Dollars)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Shareholders’ Equity
For the Years ended December 31, 2008, 2007 and 2006
(Thousands of U.S. Dollars)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
1. Description of Business
Gran Tierra Energy Inc., a Nevada corporation (the “Company” or “Gran Tierra”) is a publicly traded oil and gas company engaged in acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Colombia, Argentina and Peru.
2. Significant Accounting Policies
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting period. The Company believes that the information and disclosures presented are adequate to ensure the information presented is not misleading.
Significant accounting policies are:
Basis of consolidation
These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and changes from those estimates are recorded when known. Oil and natural gas reserves and related present value of future cash flows, impairment assessments, stock option expense, income taxes, asset retirement obligation, derivative financial instrument valuation, legal and environmental risks and exposures and any assumptions associated with valuation of oil and gas properties are all subject to estimation in the Company’s financial results.
Foreign currency translation
The functional currency of the Company, including its subsidiaries in Colombia, Argentina and Peru, is the United States dollar. Monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred. Depreciation or amortization of assets is translated at the historical exchange rates similar to the assets to which they relate.
Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are included in the consolidated statement of operations and retained earnings (accumulated deficit).
Fair value of financial instruments
The Company’s financial instruments are cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and derivatives. The fair values of these financial instruments approximate their carrying values due to their immediate or short-term nature.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Cash and cash equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted cash
During the second quarter of 2007, investors holding 948,853 units exercised their right to have Gran Tierra return to them their purchase price for the securities held in escrow. Funds of $1.3 million, held in escrow by the Bank of America were refunded to the investors in June 2007, and the securities were cancelled by the Company. No other investors have the right to cause the Company to return their purchase price for securities. During the first quarter of 2007, the $1.0 million held as a letter of credit for work commitments in Peru was returned to Gran Tierra. Export Development Canada put a guarantee in place on the Company’s behalf which resulted in the return of the restricted cash.
Allowance for doubtful accounts
The Company estimates losses on receivables based on known uncollectible accounts, if any, and historical experience of losses incurred. The allowance for doubtful receivables was $0.4 million and nil at December 31, 2008 and 2007, respectively.
Inventory
Inventory consists of crude oil in tanks and supplies. Crude oil in tanks is valued at the lower of cost or market value. Supplies are valued at cost. The cost of inventory is determined using the weighted average method. Crude oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities. Crude oil inventories at December 31, 2008 and 2007 were $0.8 million and $0.4 million, respectively. Supplies at December 31, 2008 and 2007 were $0.2 and $0.4 million, respectively.
Oil and gas properties
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Separate cost centers are maintained for each country in which the Company incurs costs. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities, however, are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and natural gas properties. Unless a significant portion of the Company’s proved reserve quantities in a particular country are sold (25% or greater), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized.
The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved properties are excluded from the amortizable base until evaluated. The cost of exploratory dry wells is transferred to proved properties and thus subject to amortization immediately upon determination that a well is dry in those countries where proved reserves exist. Future development costs are added to the amortizable base.
In countries where the Company has not recorded proved reserves, all costs associated with a property are considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. In exploration areas, related geological and geophysical (“G&G”) costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a property. G&G costs related to development projects are recorded in proved properties and therefore subject to amortization as incurred.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The Company performs a ceiling test calculation each quarter in accordance with the Securities Exchange Commission (“SEC”) Regulation S-X Rule 4-10. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at ten percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If capitalized costs exceed this limit, the excess is charged as additional depletion expense. The Company calculates future net cash flows by applying end-of-the-period prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts.
Unproved properties are assessed quarterly for possible impairments. If impairment has occurred, the impairment is transferred to proved properties. For prospects where a reserve base has not yet been established, the impairment is charged to earnings.
Asset retirement obligations
The Company provides for future asset retirement obligations on its oil and natural gas properties based on estimates established by current legislation. The asset retirement obligation is initially measured at fair value and capitalized to capital assets as an asset retirement cost. The asset retirement obligation accretes until the time the asset retirement obligation is expected to settle while the asset retirement cost is amortized over the useful life of the underlying capital assets.
The amortization of the asset retirement cost and the accretion of the asset retirement obligation are included in depletion, depreciation and accretion. Actual asset retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded as a gain or loss in the period of settlement.
Other assets
Other assets, including additions and replacements, are recorded at cost upon acquisition and include furniture and fixtures, computer equipment, automobiles and assets under capital leases. The cost of repairs and maintenance is charged to expense as incurred. Depreciation related to assets under capital leases is recorded as part of depletion, depreciation and accretion (“DD&A”) in the consolidated statement of operations. Depreciation is provided using the declining-balance-basis at a 30% annual rate for computer equipment, furniture and fixtures and automobiles.
Revenue recognition
Revenue from the production of crude oil and natural gas is recognized when title passes to the customer and when collection of the revenue is reasonably assured. For the Company’s Colombian operations, Gran Tierra’s customers take title when the crude oil is transferred to their pipeline. In Argentina, Gran Tierra transports product from the field to the customer’s refinery by truck. Revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Goodwill
Goodwill represents the excess of purchase price of business combinations over the fair value of net assets acquired and is tested for impairment at least annually unless business events indicate an impairment test is required. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for the Company’s reporting units, the fair values of the reporting units are estimated based upon estimated future cash flows of the reporting unit. The goodwill on the Company’s financial statements was a result of the acquisitions of Solana Resources Limited (“Solana”) and Argosy Energy International L.P. (“Argosy “), and relates entirely to the Colombia reporting segment. The Company performed annual impairment tests of goodwill at December 31, 2008 and 2007. Based on these assessments, no impairment of goodwill was identified.
Income taxes
Deferred income taxes are recognized using the liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax base, and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Valuation allowances are provided if, after considering available evidence, it is not more likely than not that some or all of the deferred tax assets will be realized.
The evaluation of a tax position in accordance with FIN 48 (FASB Interpretation Number 48) Accounting for Uncertainty in Income Taxes with respect to Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 109 Accounting for Income Taxes is a two-step process. The first step is recognition: The Company determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is measurement: A tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% of being realized upon settlement. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense in the consolidated statement of operations. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future.
Income (loss) per share
Basic income (loss) per share calculations are based on the net income (loss) attributable to common shareholders for the year divided by the weighted average number of common shares issued and outstanding during the period. The diluted income (loss) per share calculation is based on the weighted average number of common shares outstanding during the year, plus the effects of dilutive common share equivalents. This method requires that the dilutive effect of outstanding options and warrants issued should be calculated using the treasury stock method. This method assumes that all common share equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase common shares of the Company at the average trading price of common shares during the period. At December 31, 2008, 2007 and 2006, 100,000, 5,724,168 and 2,700,000 options to purchase common shares and warrants to purchase nil, 33,917,536 and 35,156,915 common shares, respectively, were excluded from the diluted loss per share calculation as the instruments were anti-dilutive.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Stock-based compensation
The Company follows the fair-value method of accounting for stock options granted to directors, officers and employees pursuant to FASB SFAS No. 123 (Revised). Stock-based compensation expense is included as part of oil and natural gas properties, operating and general and administrative expenses with a corresponding increase to contributed surplus. Compensation expense for options granted is based on the estimated fair value at the time of grant and the expense is recognized over the requisite service period of the option.
Accounting for Oil and Gas Derivative Instruments
The Company follows the provisions of SFAS No.133,“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of SFAS 133, the Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge as noted above. Changes in fair value of a derivative instrument designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge are recognized in the consolidated statement of operations along with the changes in fair value of the hedged item attributable to the hedged risk. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as derivative financial instrument gain or loss. The Company’s derivative instruments currently do not qualify as either a fair value hedge or a cash flow hedge.
Warrants
Upon issuance, the Company records warrants issued to purchase its common stock at fair-value; subsequently, the warrants are carried at amortized cost. The company determines the fair value of warrants issued by using the Black-Scholes option pricing model. The change of $8.6 million in the fair value of warrants issued in the 2006 Offering, arising from the amendment to the terms of the warrants in connection with the settlement of the liability for liquidated damages, was determined using Black-Scholes option pricing. Warrants were assumed on the acquisition of Solana and their fair value of $23.6 million was recorded as part of the consideration paid for the acquisition (Note 3).
New Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value under US GAAP and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 157-2 which delayed the effective date of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. These non-financial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test, asset retirement obligations and non-financial assets acquired and liabilities assumed in a business combination. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. Effective January 1, 2008, the Company adopted SFAS 157 for financial assets and liabilities. The partial adoption of SFAS 157 for financial assets and liabilities did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows. See Note 11 for information and related disclosures. Beginning January 1, 2009, the Company will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, non-financial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. The Company does not expect the provisions of SFAS 157 related to these items to have a material impact on the consolidated financial statements.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS 159 permits an entity to elect fair value as the initial and subsequent measurement attribute for many financial assets and liabilities. Entities electing the fair value option would be required to recognize changes in fair value in earnings. Entities electing the fair value option are required to distinguish on the face of the consolidated balance sheet, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. The adoption of SFAS 159 on January 1, 2008 did not impact the Company’s consolidated financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141 (R), “Business Combinations”, and SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS 141 (R) requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141 (R) and SFAS 160 are effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited and the provisions are applied prospectively. The adoption of these statements is not expected to have a material effect on the Company’s consolidated financial statements but these changes may affect potential future business combinations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”. SFAS 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133, how derivative instruments and related hedged items affect a company's financial position, financial performance and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of this statement is not expected to have a material effect on the Company’s consolidated financial statements.
In April 2008, the FASB issued FSP 142-3, “Determination of the Useful Life of Intangible Assets”. FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited. The adoption of this statement is not expected to have a material impact on the Company’s consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. It is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. The adoption of this statement is not expected to have a material effect on the Company’s consolidated financial statements.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
In June 2008, the FASB ratified the consensus reached on EITF 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”. EITF 07-05 clarifies the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which would qualify as a scope exception under SFAS 133. EITF 07-05 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption for an existing instrument is not permitted. The adoption of this EITF is not expected to have a material effect on the Company’s consolidated financial statements.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling are effective for disclosures in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2009. Early adoption is not permitted. Gran Tierra is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.
3. Business Combinations
Solana Resources Limited
On July 29, 2008, Gran Tierra announced that it had entered into an agreement providing for the business combination of Gran Tierra and Solana. Under the terms of the agreement with Solana, each Solana shareholder would receive, for each Solana common share held, either: (1) 0.9527918 of a share of Gran Tierra common stock; or (2) 0.9527918 of a common share of a Canadian subsidiary of Gran Tierra. The exchangeable shares: (a) would have the same voting rights, dividend entitlements and other attributes as Gran Tierra common stock; (b) would be exchangeable, at each stockholder's option, on a one-for-one basis into Gran Tierra common stock; and (c) subject to compliance with the listing requirements of the Toronto Stock Exchange, would be listed on the Toronto Stock Exchange. Exchangeable shares would automatically be exchanged for Gran Tierra common stock five years from closing, and in certain other events. The arrangement would also result in Solana optionholders and Solana warrantholders receiving either Solana common shares pursuant to a cashless exercise of their options or warrants or cash payments, in both cases based on the above exchange ratio. In addition, certain Solana options might be exchanged for options of Gran Tierra, and holders of Solana warrants might elect to continue to hold their warrants, which would be exercisable into shares of common stock of Gran Tierra pursuant to the terms of such warrants.
The transaction was completed November 14, 2008 pursuant to a plan of arrangement in accordance with the Business Corporations Act (Alberta). Upon completion of the transaction, Solana became an indirect wholly-owned subsidiary of Gran Tierra. On a diluted basis, upon the closing of the plan of arrangement, Solana security holders owned approximately 49% of the combined company and Gran Tierra security holders owned approximately 51% of the combined company.
The acquisition was accounted for using the purchase method, with Gran Tierra being the acquirer, whereby the Solana assets acquired and liabilities assumed are recorded at their fair values at the acquisition date of November 14, 2008 and the results of Solana have been consolidated with those of Gran Tierra from that date. The fair value of Gran Tierra’s shares was determined as the weighted average closing price of the common shares of Gran Tierra for the five-day period around the announcement date of July 29, 2008, being two days prior to and after the acquisition was agreed to and announced, and the announcement date. The fair value of each exchangeable share issued is equal to the fair value of a common share of Gran Tierra.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Under the terms of the acquisition, Gran Tierra acquired all of the issued and outstanding common shares of Solana in exchange for 120,620,967 shares comprised of 51,516,332 Gran Tierra common shares and 69,104,635 exchangeable shares of Gran Tierra Exchange Co, a wholly-owned subsidiary of Gran Tierra. In accordance with the provisions of the agreement, 490,001 Solana stock options were exchanged for 466,869 Gran Tierra stock options. Also, 7,500,000 Solana warrants were assumed on the date of the acquisition and are exchangeable for 7,145,938 Gran Tierra common shares. The fair value of the options and warrants was included as part of the consideration for this acquisition and was determined based on market price over a five day period before and after the announcement date using the Black-Scholes option pricing model with the following assumptions:
Warrants
Stock Options
Based on the conditions existing at the completion date, November 14, 2008, the fair value of the Solana warrants, as determined by Gran Tierra, exceeded the fair value of the Solana warrants, as determined by Solana, by approximately $0.6 million, and was recorded by Gran Tierra immediately as compensation expense and reported as part of general and administrative expenses.
On November 14, 2008 and prior to the November 15, 2008 deadline, as contractually agreed, Gran Tierra issued 2 million common shares to acquire the participating interest in Solana’s properties that, under the Colombian Participation Agreement entered into in 2006 with Crosby Capital LLC (“Crosby”) as part of the acquisition of Argosy, would otherwise accrue to the former owners of Argosy. The ascribed value of common shares issued has been included in the purchase consideration for the acquisition as the completion of the acquisition was dependent on the successful acquisition of this participating interest. The shares were issued in a private placement, subject to a registration rights agreement, and were registered with the SEC in February 2009.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The following table shows the allocation of the purchase price based on the fair values of the assets and liabilities acquired:
(1)
Goodwill is not deductible for tax purposes and is subject to annual impairment test.
The unaudited pro forma results for the years ended December 31, 2008 and December 31, 2007 are shown below, as if the acquisition had occurred on January 1, 2008 and January 1, 2007, respectively. Pro forma results are not indicative of actual results or future performance.
Argosy Energy International
Gran Tierra entered into a Securities Purchase Agreement dated May 25, 2006 with Crosby to acquire all of the limited partnership interests of Argosy and all of the issued and outstanding capital stock of Argosy Energy Corp. On June 20, 2006, Gran Tierra closed the Argosy acquisition and paid consideration to Crosby consisting of $37.5 million cash, 870,647 shares of the Company’s common stock and overriding and net profit interests in certain of Argosy’s assets valued at $1 million. The value of the overriding and net profit interests was based on the present value of expected future cash flows. All of Argosy’s assets are in Colombia.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The acquisition has been accounted for using the purchase method, and the results of Argosy have been consolidated with Gran Tierra from June 20, 2006. The following table shows the allocation of the purchase price based on the fair values of the assets and liabilities acquired:
(1)
Goodwill is not deductible for tax purposes and is subject to an annual impairment test.
(2)
Inventory was comprised of $0.5 million supplies and $0.1 million of oil inventory.
The unaudited pro forma results for the period ended December 31, 2006 are shown below, as if the acquisition had occurred on January 1, 2006. Pro forma results are not indicative of actual results or future performance.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
4. Segment and Geographic Reporting
The Company’s reportable operating segments are Colombia and Argentina based on a geographic organization. The Company is primarily engaged in the exploration and production of oil and natural gas. Peru is not a reportable segment because the level of activity on these land holdings is insignificant at this time and is included as part of the Corporate segment. The accounting policies of the reportable operating segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and natural gas operations before price risk management and income taxes.
The Solana assets were purchased November 14, 2008 (Note 3), therefore the Colombia and Corporate segments contain the results of its operations from that date forward.
The following tables present information on the Company’s reportable geographic segments:
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The Company’s revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. In 2008, 89% of the Company’s revenue was from one significant customer for its Colombian crude oil, Ecopetrol S.A. (“Ecopetrol”), a Colombian government agency. In Argentina, 9% of the Company’s revenue was from one significant customer, Refineria del Norte S.A.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
5. Property, Plant and Equipment
The Company has capitalized $1.9 million (2007 - $1.7 million) of general and administrative expenses directly related to the Colombian full cost center, including $0.4 million (2007 - $0.1 million) of stock-based compensation expense, and $0.8 million (2007 - $0.2 million) of general and administrative expenses in the Argentina full cost center, including $0.1 million (2007 - $0.1 million) of stock-based compensation.
The unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina and Peru. The Company has $375.9 million (2007 - $15.1 million) in unproved assets in Colombia, $4.7 million (2007 - $3.1 million) of unproved assets in Argentina and $3.6 million (2007 - $0.7 million) of unproved assets in Peru. These properties are being held for their exploration value and are not being depleted pending determination of existence of estimated proved reserves. Gran Tierra will continue to assess and allocate the unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The following is a summary of Gran Tierra’s oil and natural gas properties not subject to depletion:
6. Share Capital
Share capital
The Company’s authorized share capital consists of 325,000,002 shares of capital stock, of which 300 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share (collectively, “common stock”), and two shares designated as special voting stock, par value $0.001 per share. Outstanding share capital consists of 190,248,384 common voting shares of the Company, 37,254,143 exchangeable shares of Gran Tierra Exchange Co., and 10,984,126 exchangeable shares of Goldstrike Exchange Co. The exchangeable shares of Gran Tierra Exchange Co, were issued upon acquisition of Solana (Note 3). Each exchangeable share is exchangeable only into one common voting share of the Company. The holders of common stock are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the board of directors, in its discretion, declares from legally available funds. The holders of common stock have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the common stock. Holders of exchangeable shares have substantially the same rights as holders of common voting shares.
During the second quarter of 2007, investors holding 948,853 units, comprising 948,853 common shares and warrants to purchase 474,427 common shares, exercised their right to have the Company return to them the purchase price for the securities held in escrow. The funds of $1.3 million held in escrow by the Bank of America were refunded to the investors to complete this transaction during June, 2007, and the units were cancelled.
Warrants
At December 31, 2008, the Company had 6,732,016 warrants outstanding to purchase 3,366,008 common shares for $1.25 per share, 19,964,686 warrants outstanding to purchase 9,982,343 common shares for $1.05 per share and 7,145,938 warrants assumed upon the acquisition of Solana (Note 3) to purchase 7,145,938 common shares for CDN$2.10 per share.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
In connection with settlement of liquidated damages relating to a delay in registration of units issued in June 2006, as described in the “Registration Rights Payments” section below, the Company amended the terms of the warrants issued to stockholders in June 2006 by adjusting the exercise price from $1.75 to $1.05 and extending the term of the warrants by one year to June 2012.
Registration Rights Payments
The shares and warrants issued in 2005 and 2006 have registration rights associated with their issuance pursuant to which the Company agreed to register for resale the shares and warrants. In the event that the registration statements were not declared effective by the SEC by specified dates, the Company was required to pay liquidated damages to the purchasers of the shares and warrants.
The 15,047,606 units issued in the fourth quarter of 2005 and first quarter of 2006 had liquidated damages payable in the amount of 1% of the purchase price for each unit per month payable each month the registration statement was not declared effective beyond the mandatory effective date (July 10, 2006). The total amount recorded at December 31, 2006, for these liquidated damages was $0.3 million. There are no further liabilities associated with these shares. As of February 14, 2007, the first registration statement was declared effective by the SEC.
In June 2006, the Company sold an aggregate of 50 million units of its securities at a price of $1.50 per unit in a private offering for gross proceeds of $75 million, pursuant to three separate Securities Purchase Agreements, dated June 20, 2006, and one Securities Purchase Agreement, dated June 30, 2006 (collectively, the “2006 Offering”). Each unit comprised one share of Gran Tierra’s common stock and one warrant to purchase one-half of a share of Gran Tierra’s common stock at an exercise price of $1.75 for a period of five years, resulting in the issuance of 50 million shares of Gran Tierra’s common stock. In connection with the issuance of these securities, Gran Tierra entered into four separate Registration Rights Agreements with the investors pursuant to which Gran Tierra agreed to register for resale the shares and warrants (and shares issuable pursuant to the warrants) issued to the investors in the offering by November 17, 2006. The second registration statement was declared effective by the SEC on May 14, 2007. Gran Tierra had accrued $8.6 million in liquidated damages as of that date.
On June 27, 2007, under the terms of the Registration Rights Agreements, the Company obtained a sufficient number of consents from the signatories to the agreements waiving Gran Tierra’s obligation to pay in cash the accrued liquidated damages. The Company agreed to amend the terms of the warrants issued in the 2006 Offering by reducing the exercise price of the warrants to $1.05 and extending the life of the warrants by one year, in lieu of a cash payment for liquidated damages. The revised fair value of the warrants was determined using a Black-Scholes warrant pricing model based on a 25% volatility rate, which reflects a typical volatility rate used to value this type of financial instrument. The $8.6 million of liquidated damages has been recorded as an expense in the consolidated statement of operations in the amounts of $7.4 million for the year ended December 31, 2007, and $1.3 million in the fourth quarter of 2006, with a corresponding liability recorded on the consolidated balance sheet. The revision in the fair value of the warrants resulting from the amendment to the terms of the warrants amounted to $8.6 million (equivalent to the amount of the liquidated damages) and has been reflected on the consolidated balance sheet as an increase to the warrant value included in shareholders’ equity and a settlement of the liability for liquidated damages.
Stock options
As at December 31, 2008, the Company has a 2007 Equity Incentive Plan, formed through the approval by shareholders of the amendment and restatement of the 2005 Equity Incentive Plan, under which the Company’s board of directors is authorized to issue options or other rights to acquire shares of the Company’s common stock. On November 14, 2008, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increases the number of shares of Common Stock available for issuance thereunder from 9,000,000 shares to 18,000,000 shares.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The Company has granted options to purchase common shares to certain directors, officers, employees and consultants. Each option permits the holder to purchase one common share at the stated exercise price. The options vest over three years and have a term of ten years, or the grantee’s end of service to the Company, whichever occurs first. At the time of grant, the exercise price equals the market price. The following options have been granted:
The weighted average grant date fair value for options granted in 2008 was $1.55 (2007 - $1.10; 2006 - $0.84). The intrinsic value of options exercised in 2008 was $0.8 million (2007 and 2006 - nil).
The table below summarizes stock options outstanding at December 31, 2008:
The aggregate intrinsic value of options outstanding at December 31, 2008 is $8.9 million (2007 - $6.3 million) based on the Company’s closing stock price of $2.80 for that date. At December 31, 2008, there was $7.9 million (2007 - $2.9 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next 3 years.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The table below summarizes exercisable stock options at December 31, 2008:
The weighted average grant date fair value for options vested in 2008 was $1.17 (2007 - $0.49). The aggregate intrinsic value of options exercisable at December 31, 2008 is $4.8 million (2007 - $3.3 million) based on the Company’s closing stock price of $2.80 for that date.
In 2008, the stock-based compensation expense is $3.1 million (2007 - $1.0 million; 2006 - $0.3 million) of which $2.3 million (2007 - $0.7 million; 2006 - $0.3 million) has been recorded in general and administrative expense and $0.2 million (2007 - $0.1 million) has been recorded in operating expense in the consolidated statement of operations. In 2008, $0.6 million (2007 - $0.2 million) was capitalized as part of exploration and development costs.
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table. The Company uses historical data to estimate option exercises, expected term and employee departure behavior used in the Black-Scholes option pricing model. Expected volatilities used in the fair value estimate are based on historical volatility of the Company’s stock. The risk-free rate for periods within the contractual term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Weighted average shares outstanding
7. Asset Retirement Obligation
The December 31, 2008 asset retirement obligation is comprised of a Colombian obligation in the amount of $3.5 million (2007 - $0.4 million) and an Argentine obligation in the amount of $0.8 million (2007 - $0.4 million). Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties are as follows:
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
8. Income Taxes
The income tax expense reported differs from the amount computed by applying the Canadian statutory rate to income (loss) before income taxes for the following reasons:
Deferred tax assets and liabilities consist of the following temporary differences and loss carryforwards:
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
The Company was required to calculate a deferred remittance tax in Colombia based on 7% of profits which are not reinvested in the business on the presumption that such profits would be transferred to the foreign owners up to December 31, 2006. As of January 1, 2007, the Colombian government rescinded this law, therefore, no further remittance tax liabilities will be accrued. The historical balance which was included on the Company’s financial statements as of December 31, 2008, as part of the deferred income taxes, was $1.1 million (December 31, 2007 - $1.3 million).
The Company has accrued no amounts as of December 31, 2008, for the potential payment of interest and penalties. For the year ended December 31, 2008, the Company has not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions. The Company or one of its subsidiaries files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and other foreign jurisdictions. The Company is subject to income tax examinations for the calendar tax years ending 2005 through 2007 in all jurisdictions.
As at December 31, 2008, the Company has deferred tax assets relating to net operating loss carryforwards of $17.0 million (2007 - $15.8 million) and capital losses of $1.4 million (2007 - $3.0 million) before valuation allowances. Of these losses, $17.0 million (2007 - $9.4 million) are losses generated by the foreign subsidiaries of the Company. Of the total losses, $1.4 million (2007 - $4.0 million) will begin to expire by 2011 and $17.0 million of net operating losses (2007 - $11.9 million) will begin to expire thereafter.
9. Accrued Liabilities and Accounts Payable
The accounts payable and accrued liabilities are comprised of the following:
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
10. Commitments and Contingencies
Leases
Gran Tierra holds three categories of operating leases: office, vehicle and housing. The Company pays monthly amounts of $141,988 for office leases, $15,338 for vehicle leases, $9,400 for a compressor and $5,567 for certain employee accommodation leases in Argentina and Colombia.
Future lease payments as at December 31, 2008 are as follows:
Total rent expense for 2008 was $0.9 million (2007 - $0.3 million; 2006 - $0.2 million).
Guarantees
Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. Each indemnity, subject to certain exceptions, applies for as long as the indemnified person is a director or officer of one of the Company’s subsidiaries and/or affiliates. The maximum amount of any potential future payment cannot be reasonably estimated.
The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid. Management believes the resolution of these matters would not have a material adverse impact on the Company’s liquidity, consolidated financial position or results of operations.
Gran Tierra has contracted with a third party to provide drilling and completion services for our Colombian operations. The contract ends in February 2009 and has a remaining commitment of $1.1 million.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Contingencies
Ecopetrol and Gran Tierra Energy Colombia Ltd., (“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. At this time, no amount has been accrued in the financial statements as the Company does not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $4.7 million. To the Company’s knowledge, there are no other legal proceedings against Gran Tierra.
11. Financial Instruments and Credit Risk
The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and derivative financial instruments. The estimated fair values of the financial instruments have been determined based on the Company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair values of financial instruments approximate their book amounts due to the short-term maturity of these instruments. Most of the Company’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. The book value of the accounts receivable reflects management’s assessment of the associated credit risks.
The Company’s revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. In 2008, the Company has one significant customer for its Colombian crude oil, Ecopetrol. In Argentina, the Company has one significant customer, Refineria del Norte S.A.
The Company recognizes the fair value of its derivative instruments as assets or liabilities on the balance sheet. None of the Company's derivative instruments currently qualify as fair value hedges or cash flow hedges, and accordingly, changes in fair value of the derivative instruments are recognized as income or expense in the consolidated statement of operations and retained earnings (accumulated deficit) with a corresponding adjustment to the fair value of derivative instruments recorded on the balance sheet. Under the terms of the Credit Facility with Standard Bank (Note 12), the Company was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. In accordance with the terms of the Facility, the Company entered into a costless collar derivative instrument for crude oil based on West Texas Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period ending February 2010, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Certain of Gran Tierra’s assets and liabilities are reported at fair value in the accompanying balance sheets. The following tables provide fair value measurement information for such assets and liabilities as of December 31, 2008 and December 31, 2007.
The carrying values of cash and cash equivalents, accounts receivable (including taxes receivable) and accounts payable (including current taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2008 and December 31, 2007. These assets and liabilities are not presented in the following tables.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. When available, Gran Tierra measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
The Company uses Level 2 method to measure the fair value of its crude oil collars. The fair values of the crude oil are estimated using internal discounted cash flow calculations based upon forward commodity price curves and quotes obtained from counterparties to the agreements taking into account the credit worthiness of those brokers or counterparties.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Level 1 Fair Value Measurements
The Company does not have any assets or liabilities whose fair value is measured using this method.
Level 2 Fair Value Measurements
Crude oil collars - The fair values of the crude oil are estimated using internal discounted cash flow calculations based upon forward commodity price curves and quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements.
Level 3 Fair Value Measurements
The Company does not have any financial assets or financial liabilities whose fair value is measured using this method.
12. Credit Facilities
Effective February 28, 2007, the company entered into a credit facility with Standard Bank Plc. The facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of our petroleum reserves of a subsidiary - Gran Tierra Colombia Ltd., up to maximum of $50 million. The initial borrowing base is $7 million and the borrowing base will be re-determined semi-annually based on reserve evaluation reports. As a result of Standard Bank Plc’s review of Gran Tierra’s Mid-Year 2007 Independent Reserve Audit, the Company has received preliminary approval to increase our borrowing base to $20 million; however, this has not been pursued this further as the additional credit is not required at this time. The facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base. The facility is secured primarily by the assets of Gran Tierra Colombia. Under the terms of the facility, the Company is required to maintain compliance with specified financial and operating covenants. Gran Tierra was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the September 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. As of December 31, 2008, no amounts have been drawn-down under this facility.
Following the acquisition of Solana, effective November 14, 2008, Gran Tierra obtained access to an additional credit facility with BNP Paribas. The facility has a maturity date of December 20, 2010. The borrowing base is currently $26 million, based on the current value of petroleum reserves of the subsidiary, Solana Petroleum Exploration (Colombia) Ltd., up to a maximum of $100 million. The facility includes a letter of credit sublimit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus a margin for each quarter dependent on production for the previous quarter as follows: 3.125% for production less than 1,500 barrels of oil per day; 2.875% for production between 1,500 and 3,000 barrels of oil per day; 2.625% for production between 3,000 and 5,000 barrels of oil per day; and 2.375% for production over 5,000 barrels of oil per day. The facility is secured primarily by the assets of Solana Petroleum Exploration (Colombia) Ltd. Under the terms of the facility, we are required to maintain compliance with specified financials and operating covenants. As of December 31, 2008, no amounts have been drawn-down under this facility.
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years ended December 31, 2008, 2007 and 2006
Expressed in US dollars, unless otherwise stated
Both Standard Bank Plc and BNP Paribas have provided consent letters with regard to our acquisition of Solana, specifically providing that the acquisition would not trigger any change in control provisions under the respective facilities. The letters of consent provided by the banks each contain a number of conditions which effectively limit the time period of the consent to 150 days from the acquisition date of November 14, 2008. The Company is currently working with both banks to determine the appropriate facility going forward.
13. Subsequent Events
In connection with the Solana acquisition, Gran Tierra acquired additional office space of 4,441 square feet used by Solana as its headquarters in Calgary. The lease payments under the lease are $18,975 per month and operating and other expenses are approximately $4,000 per month. The lease expires on April 30, 2014. On February 1, 2009, the Solana subsidiary entered into a sublease for that office space with a company, of which two of Gran Tierra’s directors are shareholders and directors. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $7,050 per month plus approximately $4,000 for operating and other expenses. The terms of the sublease are consistent with current market conditions in the Calgary real estate market.
Supplementary Data (Unaudited)
1) Oil and Gas Producing Activities
The following oil and gas information is provided in accordance with SFAS 69“Disclosures about Oil and Gas Producing Activities.”
A. Reserve Quantity Information
Gran Tierra’s net proved reserves and changes in those reserves for operations are disclosed below. The net proved reserves represent management’s best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year and 100% of the reserves have been assessed by independent qualified reserves consultants, GLJ Petroleum Consultants.
Estimates of crude oil and natural gas proved reserves are determined through analysis of geological and engineering data, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. See Critical Accounting Estimates in Item 7 for a description of Gran Tierra’s reserves estimation process.
PROVED RESERVES NET OF ROYALTIES (2)
(1)
Proved developed oil and gas reserves are expected to be recovered through existing wells with existing equipment and operating methods.
(2)
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered “proved” if they can be produced economically, as demonstrated by either actual production or conclusive formation testing.
B. Capitalized Costs
C. Costs Incurred - Period & Year Ended December 31, 2008
D. Results of Operations for Producing Activities - Year Ended December 31,
E. Standardized Measure of Discounted Future Net Cash Flows and Changes
The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying year end prices to Gran Tierra’s after royalty share of estimated annual future production from proved oil and gas reserves. The calculated weighted average oil prices at December 31, 2008 were $41.23 for Colombia and $36.17 for Argentina. The calculated weighted average oil prices at December 31, 2007 were $71.28 for Colombia and $38.76 for Argentina. The calculated weighted average oil prices at December 31, 2006 were $48.66 for Colombia and $36.78 for Argentina. The calculated weighted average production costs at December 31, 2008 were $12.21 for Colombia and $13.05 for Argentina. The calculated weighted average production costs at December 31, 2007 were $12.30 for Colombia and $30.24 for Argentina. The calculated weighted average production costs at December 31, 2006 were $10.73 for Colombia and $21.93 for Argentina. Future development and production costs to be incurred in producing and further developing the proved reserves are based on year end cost indicators. Future income taxes are computed by applying year end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows.
Discounted future net cash flows are calculated using 10% mid-year discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.
The Company believes this information does not in any way reflect the current economic value of its oil and gas producing properties or the present value of their estimated future cash flows as:
\
Changes in the Standardized Measure of Discounted Future Net Cash Flows
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
2) Summarized Quarterly Financial Information
1) The fourth quarter reflects the results of Solana subsequent to date of acquisition November 14, 2008
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act) that are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions.
Our management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as required by Rule 15d-15 of the Exchange Act. Based on their evaluation, Gran Tierra’s principal executive and principal financial officers have concluded that Gran Tierra’s disclosure controls and procedures were effective as of December 31, 2008.
Management’s Annual Report on Internal Control Over Financial Reporting
Gran Tierra’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Gran Tierra, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of Gran Tierra’s management, including our principal executive and principal financial officers, Gran Tierra conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that its internal control over financial reporting was effective as of December 31, 2008.
Management’s evaluation of Gran Tierra’s internal control over financial reporting as at December 31, 2008, excluded the internal control over financial reporting of Solana Resources Limited, which was acquired on November 14, 2008, and whose financial statements constitute 83.5% and 82.8% of net and total assets, respectively, 3.4% of revenues, and a net loss of $10.8 million included in net income of $23.5 million of the consolidated financial statement amounts as of and for the year ended December 31, 2008.
The effectiveness of Gran Tierra’s internal control over financial reporting as of December 31, 2008 has been audited by Deloitte & Touche LLP, independent registered chartered accountants.
Remediation of Material Weakness
Management’s evaluation of Gran Tierra’s internal control over financial reporting as at December 31, 2008, included the evaluation of the operating effectiveness of controls which were established in the third quarter of 2008 in relation to the remediation of the material weakness disclosed in Gran Tierra’s Form 10-K/A for the year ended December 31, 2007, filed with the Securities and Exchange Commission on May 12, 2008. The material weakness related to a misclassification of cash flows from operating activities, with a corresponding offset to cash flows from investing activities, in the statement of cash flows. The control over the entry of data into a spreadsheet used in the preparation of the statement of cash flows and the monitoring thereof was not sufficiently precise to prevent the misclassification from occurring. In the third quarter of 2008, management remediated this material weakness by: creating new worksheets requiring detailed reconciliations of all statement of cash flow line items and business segment changes in accounts payable and accrued liability balances used to determine cash flows from operating and investing activities; implemented review procedures to ensure proper segregation of duties through identification of roles and responsibilities; and, added an additional qualified staff at financial reporting management level to enhance segregation of duties in the preparation, review and approval of the Statement of Cash Flows. Management believes that the above steps have remediated the material weakness.
Changes in Internal Control Over Financial Reporting
There were no changes in Gran Tierra’s internal control over financial reporting during the fourth quarter of 2008 that has materially affected, or is reasonably likely to materially affect, Gran Tierra’s internal control over financial reporting.
Report of Independent Registered Chartered Accountants
To the Board of Directors and Shareholders of Gran Tierra Energy Inc.
We have audited the internal control over financial reporting of Gran Tierra Energy Inc. and subsidiaries (the “Company”) as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Solana Resources Limited, which was acquired on November 14, 2008 and whose financial statements constitute 83.5% and 82.8% of net and total assets, respectively, 3.4% of revenues, and a net loss of $10.8 million included in net income of $23.5 million of the consolidated financial statement amounts as of and for the year ended December 31, 2008. Accordingly, our audit did not include the internal control over financial reporting at Solana Resources Limited. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with Canadian generally accepting auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2008 of the Company and our report dated February 24, 2009 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Canada
February 24, 2009
Item 9A(T). Controls and Procedures
Not applicable.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by Item 10 of Form 10-K with respect to Item 401 of Regulation S-K regarding our directors is incorporated herein by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our definitive Proxy Statement for the 2009 Annual Meeting of Stockholders (the “Proxy Statement”), a copy of which will be filed with the Securities and Exchange Commission on or before April 30, 2009.
The information required by Item 10 of Form 10-K with respect to Item 405 of Regulation S-K regarding section 16(a) beneficial ownership reporting compliance is incorporated by reference from the information contained in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement.
For information with respect to our executive officers, see “Executive Officers of the Registrant” at the end of Part I of this report, following Item 4.
The information required by Item 10 of Form 10-K with respect to Items 407(c)(3), 407(d)(4) and 407(d)(5) is incorporated by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our Proxy Statement.
Adoption of Code of Ethics
Gran Tierra has adopted a Code of Business Conduct and Ethics (the “Code”) applicable to all of its Board members, employees and executive officers, including its Chief Executive Officer (Principal Executive Officer), and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer). Gran Tierra has made the Code available on its website at http://www.grantierra.com/policies-practices/ .
Gran Tierra intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra’s Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer by posting such information on its website at http://www.grantierra.com/policies-practices/ . There were no amendments to the Code or waivers granted thereunder relating to the Principal Executive Officer, Principal Financial Officer or Principal Accounting Officer during fiscal 2008.
Item 11.
Item 11. Executive Compensation
The information required by Item 11 of Form 10-K is incorporated herein by reference from the information contained in the sections entitled “Executive Compensation and Related Information,” “Director Compensation,” “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation” in our Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 of Form 10-K with respect to Item 403 of Regulation S-K regarding security ownership of certain beneficial owners and management is incorporated herein by reference from the information contained in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in the Proxy Statement.
The information required by Item 12 of Form 10-K with respect to Item 201(d) of Regulation S-K regarding our equity compensation plans as of December 31, 2008 is incorporated herein by reference from the information contained in the section entitled “Stockholder Approval of Stock Plans” in the Proxy Statement.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Item 13 of Form 10-K is incorporated herein by reference from the information contained in the sections entitled “Certain Relationships and Related Transactions” and, with respect to director independence, the section entitled “Proposal 1 - Election of Directors,” in our Proxy Statement.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by Item 14 of Form 10-K is incorporated herein by reference from the information contained in the sections entitled “Principal Accountant Fees and Services” and “Audit Committee Pre-Approval Policies and Procedures’’ in our Proxy Statement.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this Annual Report on Form 10-K:
(1) Financial Statements
The following documents are included as Part II, Item 8. of this Annual Report on Form 10-K:
(2) Financial Statement Schedules
None.
(3) Exhibits
See the Exhibit Index which follows the signature page of this Annual Report on Form 10-K, which is incorporated herein by reference.
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Dana Coffield and Martin Eden, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Name
Title
Date
/s/ Dana Coffield
Chief Executive Officer and
President
February 24, 2009
Dana Coffield
(Principal Executive Officer)
/s/ Martin Eden
Chief Financial Officer
February 24, 2009
Martin Eden
(Principal Financial and Accounting Officer )
/s/ Jeffrey Scott
Chairman of the Board, Director
February 26, 2009
Jeffrey Scott
/s/ Verne Johnson
Director
February 24, 2009
Verne Johnson
/s/ Nicholas G. Kirton
Director
February 24, 2009
Nicholas G. Kirton
/s/ J. Scott Price
Director
February 24, 2009
J. Scott Price
/s/ Ray Anthony
Director
February 24, 2009
Ray Anthony
/s/ Walter Dawson
Director
February 24, 2009
Walter Dawson
EXHIBIT INDEX
Exhibit
No.
Description
Reference
2.1
Certain Acquisition Agreements
See Exhibits 10.1, 10.3, 10.5, 10.18, 10.46 and 10.47
2.2
Arrangement Agreement, dated as of July 28, 2008, by and among Gran Tierra Energy Inc., Solana Resources Limited and Gran Tierra Exchangeco Inc.
Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on August 1, 2008.
2.3
Amendment No. 2 to Arrangement Agreement, which includes the Plan of Arrangement, including appendices.
Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-3 (Reg. No. 333-153376), filed with the SEC on October 10, 2008.
3.1
Articles of Incorporation.
Incorporated by reference to Exhibit 3.1 to the Form SB-2, as amended, filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).
3.2
Certificate Amending Articles of Incorporation.
Incorporated by reference to Exhibit 3.2 to the Form SB-2, as amended, and filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).
3.3
Certificate Amending Articles of Incorporation.
Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
3.4
Certificate of Amendment to Articles of Incorporation.
Incorporated by reference to Exhibit 3.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 1, 2006 (File No. 333-111656).
3.5
Certificate Amending Articles of Incorporation.
Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 19, 2008 (File No. 000-52594).
3.6
Certificate Amending Articles of Incorporation.
Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 19, 2008 (File No. 000-52594).
3.7
Fifth Amended and Restated Bylaws of Gran Tierra Energy Inc.
Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2008 (File No. (File No. 000-52594).
4.1
Reference is made to Exhibits 3.1 to 3.7.
4.2
Form of Warrant issued in 2005.
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
4.3
Form of Warrant issued to institutional and retail investors in connection with the private offering in June 2006.
Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.1
Share Purchase Agreement by and between Goldstrike Inc. and Gran Tierra Energy Inc. dated as of November 10, 2005.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.2
Form of Registration Rights Agreement by and among Goldstrike Inc. and the purchasers named therein.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
10.3
Assignment Agreement by and between Goldstrike Inc. and Gran Tierra Goldstrike Inc. dated as of November 10, 2005.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.4
Voting Exchange and Support Agreement by and between Goldstrike, Inc., 1203647 Alberta Inc., Gran Tierra Goldstrike Inc. and Olympia Trust Company dated as of November 10, 2005.
Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.5
Form of Split Off Agreement by and among Goldstrike Inc., Dr. Yenyou Zheng, Goldstrike Leasco Inc. and Gran Tierra Energy Inc.
Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
Exhibit
No.
Description
Reference
10.6
Reserved
10.7
Reserved
10.8
Reserved
10.9
Reserved
10.10
Form of Indemnity Agreement. *
Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 2, 2008 (File No. 333-111656).
10.12
Equity Incentive Plan. *
Incorporated by reference to Exhibit 10.11 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).
10.13
Form of Subscription Agreement.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).
10.14
Details of the Goldstrike Special Voting Share.
Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).
10.15
Goldstrike Exchangeable Share Provisions.
Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).
10.16
Refinery Contract between Refinor S.A. and Dong Wong Corporation - Golden Oil Corporation.
Incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).
10.17
Contract between Compañia General de Combustibles S.A. and Gran Tierra Energy Argentina S.A.
Incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656)
10.18
Securities Purchase Agreement, dated as of May 25, 2006, by and between Gran Tierra Energy, Inc and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 1, 2006 (File No. 333-111656).
10.20
Form of Securities Purchase Agreement, dated as of June 20, 2006, by and among the Company and retail investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.
Incorporated by reference to Exhibit 10.20 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
Exhibit
No.
Description
Reference
10.21
Form of Subscription Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and retail investors subscribing for units of Gran Tierra Energy Inc. securities in a private offering.
Incorporated by reference to Exhibit 10.21 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.22
Securities Purchase Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and CD Investment Partners, Ltd.
Incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.23
Form of Registration Rights Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and institutional investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.
Incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.24
Form of Registration Rights Agreement, dated as of June 20, 2006, by and among Gran Tierra Energy Inc. and retail investors purchasing units of Gran Tierra Energy Inc. securities in a private offering.
Incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.25
Registration Rights Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and CD Investment Partners, Ltd.
Incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.26
Reserved
10.27
Registration Rights Agreement, dated as of June 20, 2006, by and between Gran Tierra Energy Inc. and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.27 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).
10.28
Form of Securities Purchase Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.
Incorporated by reference to Exhibit 10.28 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).
10.29
Form of Subscription Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.
Incorporated by reference to Exhibit 10.29 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).
10.30
Form of Registration Rights Agreement, dated as of June 30, 2006, by and among Gran Tierra Energy Inc. and the investors in the June 30, 2006 closing of the Offering.
Incorporated by reference to Exhibit 10.30 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2006 (File No. 333-111656).
10.31
Form of Escrow Agreement.
Incorporated by reference to Exhibit 10.31 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.32
Form of Registration Rights Agreement by and among Goldstrike Inc. and the purchasers named therein.
Incorporated by reference to Exhibit 10.32 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.33
Form of Subscription Agreement by and among Goldstrike Inc., Gran Tierra Energy, Inc. and the investor identified therein.
Incorporated by reference to Exhibit 10.33 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.34
Form of Registration Rights Agreement by and among Gran Tierra Energy, Inc. f/k/a Goldstrike, Inc. and the purchasers named therein.
Incorporated by reference to Exhibit 10.34 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
Exhibit
No.
Description
Reference
10.35
Form of Subscription Agreement by and among Gran Tierra Energy, Inc. f/k/a Goldstrike, Inc. and the investor identified therein.
Incorporated by reference to Exhibit 10.35 to Form SB-2, as amended, filed with the Securities and Exchange Commission on December 7, 2006 (File No. 333-111656).
10.36
Reserved
10.37
Credit Agreement dated February 22, 2007, by and among Gran Tierra Energy Inc, Gran Tierra Energy Colombia, Ltd., Argosy Energy Corp., and Standard Bank Plc.
Incorporated by reference to Exhibit 10.1 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.38
Note For Loans, dated February 22, 2007, by the Company in favor of Standard Bank Plc.
Incorporated by reference to Exhibit 10.2 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.39
GP Pledge Agreement, dated as of February 22, 2007, by the Company in favor of Standard Bank Plc.
Incorporated by reference to Exhibit 10.3 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.40
Partnership Pledge Agreement, dated as of February 22, 2007, by and among the Company and Argosy Energy Corp., in favor of Standard Bank Plc.
Incorporated by reference to Exhibit 10.4 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.41
Collection Account Pledge Agreement, dated as of February 22, 2007, by Gran Tierra Energy Colombia, Ltd. in favor of Standard Bank Plc.
Incorporated by reference to Exhibit 10.5 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.42
ISDA 2002 Master Agreement, dated as of February 22, 2007, by and among the Company and Standard Bank Plc, and the Schedule thereto.
Incorporated by reference to Exhibit 10.6 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.43
Blocked Account Control Agreement, dated as of February 22, 2007, by and among Gran Tierra Energy Colombia, Ltd., Standard Bank Plc and JPMorgan Chase Bank.
Incorporated by reference to Exhibit 10.7 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.44
Share Pledge Agreement, dated as of February 22, 2007, by and among the Company and Standard Bank Plc.
Incorporated by reference to Exhibit 10.8 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.45
First Priority Open Pledge Agreement Over Credit Rights Derived From A Crude Oil Commercial Sales Agreement, dated as of February 22, 2007, by and among Gran Tierra Energy Colombia, Ltd. and Standard Bank Plc.
Incorporated by reference to Exhibit 10.9 to the current report on Form 8-K/A filed with the Securities and Exchange Commission on March 6, 2007 (File No. 333-111656).
10.46
Contract between Ecopetrol S.A., and Argosy Energy International, for the sale of crude oil, dated December 1, 2006
Incorporated by reference to Exhibit 10.46 to the Annual Report on Form 10-KSB filed with the Securities and Exchange Commission on March 30, 2007 (File No. 333-111656).
10.47
Palmar Largo Assignment Agreement, dated September 1, 2005, between Don Won Corporation (Sucursal Argentina), and Gran Tierra Inc.
Incorporated by reference to Exhibit 10.47 to the Annual Report on Form 10-KSB filed with the Securities and Exchange Commission on March 30, 2007 (File No. 333-111656).
10.48
Escrow Agreement dated as of the 20th day of June, 2006, among Gran Tierra Energy, Inc. and McGuireWoods LLP, as Escrow Agent
Incorporated by reference to Exhibit 10.48 to the Form S-1/A filed with the Securities and Exchange Commission on May 4, 2007 (File No. 333-140171).
10.49
Reserved
10.50
Form of Liquidated Damages Waiver
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on August 14, 2007 (File No. 333-111656).
10.51
Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 17, 2008 (File No. 000-52594).
10.52
Form of Option Agreement under the Company’s 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 99.1 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).
10.53
Form of Grant Notice under the Company’s 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 99.2 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).
10.54
Form of Exercise Notice under the Company’s 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 99.3 to the current report on Form 8-K filed with the Securities and Exchange Commission on December 21, 2007 (File No. 000-52594).
10.55
Colombian Participation Agreement, dated as of June 22, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.55 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008.
10.56
Amendment No. 1 to Colombian Participation Agreement, dated as of November 1, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.56 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008.
10.57
Amendment No. 2 to Colombian Participation Agreement, dated as of July 3, 2008, between Gran Tierra Energy Inc. and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q/A, filed with the SEC on November 19, 2008.
10.58
Employment Agreement, dated November 4, 2008, between Gran Tierra Energy Inc. and Dana Coffield.*
Filed Herewith
10.59
Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Martin Eden. *
Incorporated by reference to Exhibit 10.58 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008.
10.60
Employment Agreement, dated November , 2008, between Gran Tierra Energy Inc. and Edgar Dyes. *
Filed Herewith
10.61
Employment Agreement, dated November 4, 2008, between Gran Tierra Energy Inc. and Max Wei. *
Filed Herewith
10.62
Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Rafael Orunesu. *
Incorporated by reference to Exhibit 10.61 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008.
10.63
Voting and Exchange Trust Agreement, dated as of November 14, 2008, between Gran Tierra Energy Inc., Gran Tierra Exchangeco Inc. and Computershare Trust Company of Canada.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on November 17, 2008.
10.64
Support Agreement, dated as of November 14, 2008, between Gran Tierra Energy Inc., Gran Tierra Callco ULC and Gran Tierra Exchangeco Inc.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on November 17, 2008.
10.65
Amendment No. 3 to Participation Agreement, dated as of December 31, 2008, by and among Gran Tierra Energy Colombia, Ltd., Gran Tierra Energy Inc. and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.66
Amendment No. 1 and Waiver to Credit Agreement, dated as of January 1, 2009, by and among Gran Tierra Energy Colombia, Ltd., Gran Tierra Energy Inc., Argosy Energy, LLC and Standard Bank Plc.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.67
Release of Partnership Pledge Agreement, dated as of January 1, 2009, by and among Gran Tierra Energy Inc., Argosy Energy, LLC and Standard Bank Plc.
Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.68
Release of GP Pledge Agreement, dated as of January 1, 2009, by and between Gran Tierra Energy Inc. and Standard Bank Plc.
Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.69
Partnership Pledge Agreement, dated as of January 1, 2009, by and among GTE Colombia Holdings LLC, Argosy Energy, LLC and Standard Bank Plc.
Incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.70
GP Pledge Agreement, dated as of January 1, 2009, by and between GTE Colombia Holdings LLC and Standard Bank Plc
Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.71
Executive Officer Cash Bonus Compensation and 2009 Cash Compensation*
Incorporated by reference to Item 5.02 of the Current Report on Form 8-K, filed with the SEC on January 7, 2009.
10.72
Form of Shareholder Support Agreement Respecting the Arrangement Involving Solana Resources Limited, Gran Tierra Energy Inc. and Gran Tierra Exchangeco Inc. (Solana Shareholders)
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on August 1, 2008.
10.73
Form of Shareholder Support Agreement Respecting the Arrangement Involving Solana Resources Limited, Gran Tierra Energy Inc. and Gran Tierra Exchangeco Inc. (Gran Tierra Stockholders)
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on August 1, 2008.
Exhibit
No.
Description
Reference
21.1
List of subsidiaries.
Filed herewith.
23.1
Consent of Deloitte & Touche LLP
Filed herewith.
23.2
Consent of GLJ Petroleum Consultants
Filed herewith.
24.1
Power of Attorney.
See signature page.
31.1
Certification of Principal Executive Officer
Filed herewith.
31.2
Certification of Principal Financial Officer
Filed herewith.
32.1
Certification of Principal Executive and Financial Officers
Filed herewith.
* Management contract or compensatory plan or arrangement.