GRAN TIERRA ENERGY INC.
10-Ks and 10-Qs
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UNITED STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-K
(Mark
One)
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For
the year ended December 31, 2009
OR
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o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For
the transition period from _____________ to _____________
Commission
File Number 001-34018
(Exact
name of registrant as specified in its charter)
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Nevada
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98-0479924
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(State
or other jurisdiction of
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(I.R.S.
Employer
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incorporation
or organization)
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Identification
No.)
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300, 611
10
th
Avenue
SW
Calgary,
Alberta, Canada
(Address
of principal executive offices, including zip code)
(403) 265-3221
(Registrant’s
telephone number, including area code)
Securities
Registered Pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on Which Registered
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Common
Stock, par value $0.001 per share
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NYSE Amex (formerly
American Stock Exchange)
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Toronto
Stock Exchange
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Securities
Registered Pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes
x
No
¨
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes
¨
No
x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes
¨
No
x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes
x
No
¨
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes
¨
No
¨
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filer
x
Accelerated
filer
¨
Non-accelerated
filer
¨
(do not check if a
smaller reporting company) Smaller reporting company
¨
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Yes
¨
No
x
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold as of the last business day of the registrant’s most recently
completed second fiscal quarter was approximately $789,170,812 (including shares
issuable upon exercise of exchangeable shares). Aggregate market value excludes
an aggregate of 1,082,633 shares of common stock and 11,633,442 shares issuable
upon exercise of exchangeable shares held by officers and directors and by each
person known by the registrant to own 5% or more of the outstanding common stock
on such date. Exclusion of shares held by any of these persons should not be
construed to indicate that such person possesses the power, direct or indirect,
to direct or cause the direction of the management or policies of the
registrant, or that such person is controlled by or under common control with
the registrant.
On
February 22, 2010, the following numbers of shares of the registrant’s capital
stock were outstanding: 227,414,754 shares of the registrant’s Common Stock,
$0.001 par value; one share of Special A Voting Stock, $0.001 par
value, representing 8,642,857 shares of Gran Tierra Goldstrike Inc.,
which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock;
and one share of Special B Voting Stock, $0.001 par
value, representing 12,581,523 shares of Gran Tierra Exchangeco Inc.,
which are exchangeable on a 1-for-1 basis into the registrant’s Common
Stock.
DOCUMENTS
INCORPORATED BY REFERENCE
The
information required by Part III of this report, to the extent not set
forth herein, is incorporated by reference from the Registrant’s definitive
proxy statement relating to the 2010 annual meeting of stockholders, which
definitive proxy statement will be filed with the Securities and Exchange
Commission within 120 days after the fiscal year to which this Report
relates.
GRAN
TIERRA ENERGY INC.
ANNUAL
REPORT ON FORM 10-K
Year
ended December 31, 2009
TABLE
OF CONTENTS
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Page
No.
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PART I
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Item
1.
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Business
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3
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Item
1A.
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Risk
Factors
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13
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Item
1B.
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Unresolved
Staff Comments
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23
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Item
2.
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Properties
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23
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Item
3.
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Legal
Proceedings
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35
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Item
4.
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Reserved
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35
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PART II
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Item
5.
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Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
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36
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Item
6.
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Selected
Financial Data
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39
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Item
7.
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Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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40
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Item
7A.
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Quantitative
and Qualitative Disclosures About Market Risk
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62
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Item
8.
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Financial
Statements and Supplementary Data
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64
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Item
9.
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
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95
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Item
9A.
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Controls
and Procedures
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95
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Item
9A(T)
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Controls
and Procedures
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97
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Item
9B.
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Other
Information
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97
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PART III
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Item
10.
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Directors,
Executive Officers and Corporate Governance
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97
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Item
11.
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Executive
Compensation
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97
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Item
12.
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Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
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97
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Item
13.
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Certain
Relationships and Related Transactions, and Director
Independence
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98
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Item
14.
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Principal
Accounting Fees and Services
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98
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PART IV
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Item
15.
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Exhibits,
Financial Statement Schedules
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98
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SIGNATURES
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99
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2
This
Annual Report on Form 10-K, particularly in Item 1. “Business”, Item 2
“Properties” and Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 (the Securities Act)
and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). All
statements other than statements of historical facts included in this Annual
Report on Form 10-K including without limitation statements in the Management’s
Discussion and Analysis of Financial Condition and Results of Operations
regarding our financial position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of our management for future
operations, covenant compliance, capital spending plans and those statements
preceded by, followed by or that otherwise include the words “believe”,
“expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”,
“plans”, “objective”, “should”, or similar expressions or variations on such
expressions are forward-looking statements. We can give no assurances that the
assumptions upon which the forward-looking statements are based will prove to be
correct and because forward-looking statements are subject to risks and
uncertainties, actual results may differ materially from those expressed or
implied by the forward-looking statements. There are a number of risks,
uncertainties and other important factors that could cause our actual results to
differ materially from the forward-looking statements, including, but not
limited to, those set out in Part I, Item 1A “Risk Factors” in this Annual
Report on Form 10-K. The information included herein is given as of the filing
date of this Form 10-K with the Securities and Exchange Commission (“SEC”) and,
except as otherwise required by the federal securities laws, we disclaim any
obligations or undertaking to publicly release any updates or revisions to any
forward-looking statement contained in this Annual Report on Form 10-K to
reflect any change in our expectations with regard thereto or any change in
events, conditions or circumstances on which any such statement is
based.
General
Gran
Tierra Energy Inc. together with its subsidiaries (“Gran Tierra” or “we”) is an
independent international energy company engaged in oil and gas acquisition,
exploration, development and production. We own oil and gas properties in
Colombia, Argentina 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 (U.S.) dollars, unless otherwise indicated.
On
November 14, 2008, we completed the acquisition of all of the outstanding common
stock of Solana Resources Limited ("Solana") pursuant to a plan of arrangement
under the
Business
Corporations Act
(Alberta)
.
Solana was an international
resource company engaged in the acquisition, exploration, development and
production of oil and natural gas. Solana was incorporated in Canada with its
head office in Calgary, Alberta, Canada.
In 2009,
our geographic focus was on South America. We focused on development of
producing fields and generation of exploration prospects in Colombia. In
Argentina we maintained existing production and worked on the evaluation of a
natural gas project. In Peru we worked on our Environmental Impact Assessments
and on evaluating data in order to prepare for 2010’s seismic acquisition and
drilling program. We also expanded our geographic focus by opening an office in
Brazil, and also establishing a business development team in Calgary to pursue
opportunities in Brazil.
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 www.grantierra.com. To access our
SEC filings, select SEC Filings from the investor relations menu on our website,
which will provide a list of our SEC filings. Our website address is provided
solely for informational purposes. We do not intend, by this reference, that our
website should be deemed to be part of this Annual Report. Any materials we have
filed with the SEC may be read and/or copied at the SEC’s Public Reference Room
at 100 F Street N.E. Room 1580, Washington, D.C. 20549. You may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy
and information statements, and other information regarding us. The SEC’s
website address is www.SEC.gov.
The Oil and Gas Business
In the
discussion that follows, and in Item 2 “Properties”, we discuss our interests in
wells and/or acres in gross and net terms. Gross oil and natural gas wells or
acres refer to the total number of wells or acres in which we own a working
interest. Net oil and natural gas wells or acres are determined by multiplying
gross wells or acres by the working interest that we own in such wells or acres.
Working interest refers to the interest we own in a property, which entitles us
to receive a specified percentage of the proceeds of the sale of oil and natural
gas, and also requires us to bear a specified percentage of the cost to explore
for, develop and produce that oil and natural gas. A working interest owner that
owns a portion of the working interest may participate either as operator or by
voting 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.
3
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 hydrocarbon-bearing
reservoir. A development well is a well drilled to develop a hydrocarbon-bearing
reservoir that is already discovered. Exploration and development wells are
tested during and after the drilling process to determine if they have oil or
natural gas that can be produced economically in commercial quantities. If they
do, the well will be completed for production, which could involve any range of
a wide variety of equipment, the specifics of which depend on a number of
technical geological and engineering considerations. If there is no oil or
natural gas (a “dry” well), or there is oil and natural gas but the quantities
are too small and/or too difficult to produce, the well will be abandoned.
Abandonment is a completion operation that involves closing or “plugging” the
well and remediating the drilling site. An injector well is a development well
that will be used to inject fluid into a reservoir to increase production from
other wells.
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. In 2009 we added exploration blocks by
converting our two Technical Evaluation Areas to three exploration and
exploitation blocks. As a result of these acquisitions we hold as of December
31, 2009:
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1,056,803
gross acres in Colombia (753,376 net) covering twelve Exploration and
Production contracts, three of which are producing and all but one are
operated by Gran Tierra;
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1,628,473
gross acres (1,290,644 net) in Argentina covering seven Exploration and
Production contracts, five of which are producing, and all but one are
operated by Gran Tierra; and
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4
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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.
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Colombia
Putumayo
Basin Pipeline Infrastructure
5
In
Colombia in 2009, on the Chaza Block, we continued the development of our
Costayaco field, completing Costayaco-6 as an injector well and drilling four
development wells (Costayaco 7 through 10). The Costayaco field reached its
production plateau rate during 2009. We also drilled one exploration well on the
Chaza block in December, which was plugged and abandoned in January 2010. On our
Rio Magdalena block, we acquired seismic data, completed our Popa-2 well which
was drilled in 2008 and commenced a long term production test on this well. We
drilled one other exploration well in 2009, on the Guachiria Norte block, which
we plugged and abandoned. One exploration well, which was plugged and abandoned,
was drilled on the Talora block. We also acquired and evaluated seismic data on
several other blocks. We were awarded three new exploration and exploitation
blocks in Colombia – Rumiyaco, Piedemonte Norte and Piedemonte Sur - that came
from the two Technical Evaluation Areas to which we previously had rights. We
continued to execute our ongoing rationalization of non-core properties in our
portfolio. We sold three blocks – Guachiria, Guachiria Norte and Guachiria Sur;
we entered into letters of intent with regard to the sale of our interests in
two other blocks – Catguas and Garibay; and we entered into assignment
agreements for two blocks – Rio Magdalena and Mecaya. Finally, we relinquished
our rights to two blocks – Talora and San Pablo.
Details
of our 2010 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 2009, we completed several successful workovers, upgraded
facilities on our El Vinalar and El Chivil blocks and installed production
facilities and commenced production on our Ipaguazu block. We conducted a
feasibility study for production on the natural gas well on our Valle Morado
block, which was considered successful, as the well showed signs of production
capability. Finally, we relinquished our rights to the Nacatimbay
block.
Details
of our 2010 plans are contained in Item 2 “Properties.”
6
Peru
Gran
Tierra lands highlighted in yellow. Other licenses in grey. Green dots are
producing oil fields
In Peru
in 2009, we completed Environmental Impact Assessments (“EIAs”) over blocks 122
and 128, along with engineering feasibility studies on both blocks and
geological studies. We opened two offices in Peru in the fourth quarter, an
administrative office in Lima and an operational office in Iquitos.
Details
of our 2010 plans are contained in Item 2 “Properties.”
Brazil
In
September 2009, we opened a business development office in Rio de Janiero,
Brazil. We are currently looking for opportunities to acquire oil and gas assets
in that country. We have staff in Brazil and in Calgary evaluating oil and gas
investment opportunities and developing business relationships. We have no oil
and gas properties in Brazil to date.
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, 2009 and 2008, 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, 2007, were $112.8
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, Peru, and Brazil; we will consider
other regions for future growth should those regions make strategic and
commercial sense in creating additional value.
We have
applied a two-stage approach to growth, initially establishing a base of
production, development and exploration assets by selective acquisitions, and
secondly achieving 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, that have stable legal systems, that offer
opportunities that we believe have been previously ignored or undervalued,
and that have an active market with many available
deals;
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7
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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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Manage
asset and drilling portfolios closely, assessing value to the company and
making changes where needed.
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Research
and Development
We have
not expended any resources on pursuing research and development initiatives. We
use existing technology and processes for executing our business
plan.
Markets
and Customers
Ecopetrol
S.A. (“Ecopetrol”), the Colombian National Oil Company, 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 transport oil from our discoveries
at Juanambu and Costayaco to our existing pipeline system, replacing previous
transportation by truck. In 2009, we reached the maximum production rate from
our Costayaco field in the Putumayo Basin of approximately 13,000 BOPD after
royalties. The majority of the oil produced is transported by pipeline. Varying
amounts of oil are trucked from Santana Station to Ecopetrol’s storage terminal
at Orito and 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. In 2009, we received 25% of our revenue
in Colombian pesos, and 75% of revenue in U.S. dollars. Under new contracts with
Ecopetrol effective for 2010, we will receive 100% of our revenue in U.S.
dollars. Sales to Ecopetrol accounted for 94% of our revenues in 2009, 89% of
our revenues in 2008, and 75% of our revenues in 2007.
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 2009 and 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. The purchaser of most of our oil in
Argentina is Refineria del Norte S.A. (“Refiner S.A.”) Starting in December 2008
and ending in May 2009, we shipped 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 U.S. 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. Sales to
Refiner accounted for 5.8% of our revenues in 2009, 9% of our revenues in 2008,
and 25% of our revenues in 2007.
There
were no sales in any other country other than Colombia and Argentina in 2009,
2008 and 2007.
8
See
“
Our Oil Sales Will Depend on
a Relatively Small Group of Customers, Which Could Adversely Affect Our
Financial Results
” and “
Negative Economic, Political and
Regulatory Developments in Argentina May Negatively Affect our Operations
” in Item 1A “Risk Factors” for a description of the risks faced by our
dependency on a small number of customers and the regulatory systems under which
we operate.
Competition
The oil
and gas industry is highly competitive. We face competition from both local and
international companies in acquiring properties, contracting for drilling and
other oil field equipment and securing trained personnel. Many of these
competitors have financial and technical resources that exceed ours, and we
believe that these companies have a competitive advantage in these areas. Others
are smaller, and we believe our technical and financial capabilities give us a
competitive advantage over these companies.
See
“Competition in Obtaining Rights to
Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair
Our Business”
in Item 1A “Risk Factors” for risks associated with
competition.
Geographic
Information
Information
regarding our geographic segments, including information on revenues, assets,
expenses, and income can be found in Note 4 to the Financial Statements, Segment
and Geographic Reporting, in Item 8 “Financial Statements and Supplementary
Data”, which information is incorporated by reference here. Long lived assets
are Property, Plant and Equipment, which includes all oil and gas assets,
furniture and fixtures, automobiles and computer equipment. No long lived assets
are held in our country of domicile, which is the United States of America.
Corporate assets include assets held by our corporate head office in Calgary,
Alberta, Canada, and assets held in Peru and Brazil.
Regulation
The oil
and gas industry in Colombia, Argentina, Peru and Brazil is heavily regulated.
Rights and obligations with regard to exploration, development and production
activities are explicit for each project; economics are governed by a
royalty/tax regime. Various government approvals are required for property
acquisitions and transfers, including, but not limited to, meeting financial and
technical qualification criteria in order to be certified as an oil and gas
company in the country. Oil and gas concessions are typically granted for fixed
terms with opportunity for extension.
Colombia
In
Colombia, prior to 2004, state owned Ecopetrol was the administrator of all
hydrocarbons and therefore executed contracts with oil companies under different
contractual types such as Association contracts and Shared Risk Contracts. Under
Association Contracts, the oil companies assumed all risk during the exploration
phase and Ecopetrol had the right to back-in if a discovery, commercial under
Ecopetrol’s terms, was made.
Effective
June 2004, the regulatory regime in Colombia underwent a significant change with
the formation of the
Agencia
Nacional de Hidrocarburos
or National Hydrocarbons Agency (“ANH”). The
ANH is now the administrator of the hydrocarbons in the country and therefore is
responsible for regulating the Colombian oil industry, including managing all
exploration lands. Ecopetrol became a public company owned in majority by the
state with the main purpose of exploring and producing hydrocarbons similar to
any other oil company. However, Ecopetrol continues to have rights under the
existing contracts executed with oil companies before ANH was created. Ecopetrol
continues to be the major purchaser and marketer of crude oil in Colombia, and
also operates the majority of the oil transportation infrastructure in the
country.
In
conjunction with this change, the ANH developed a new exploration risk contract
that took effect near the end of the first quarter of 2005. This Exploration and
Production Contract has significantly changed the way the industry views
Colombia. In place of the earlier association contracts in which the contractor
assumed all the exploration risk and Ecopetrol had the right to back-in
afterwards, the new agreement provides full risk/reward benefits for the
contractor. Under the terms of the contract the successful operator retains the
rights to all reserves, production and income from any new exploration block,
subject to existing royalty and tax regulations. Each contract contains an
exploration phase and a production phase. The exploration phase will contain a
number of exploration periods and each period will have an associated work
commitment. The production phase will last a number of years (usually 24) from
the declaration of a commercial hydrocarbon discovery.
Gran
Tierra operates in Colombia through two branches – Gran Tierra Energy Colombia
Ltd. and Solana Petroleum Exploration (Colombia) Ltd. Both are qualified as
operators of oil and gas properties by ANH.
When
operating under a contract, the contractor is the owner of the hydrocarbons
extracted from the contract area during the performance of operations, and pays
royalties which are collected by ANH or Ecopetrol, depending on the type of
contract. The contractor can market the hydrocarbons in any manner whatsoever,
subject to a limitation in the case of natural emergencies where the law
specifies the manner of sale.
9
Argentina
The
Hydrocarbons Law 17.319, enacted in June 1967, established the basic legal
framework for the current regulation of exploration and production of
hydrocarbons in Argentina. The Hydrocarbons Law empowers the National Executive
to establish a national policy for development of Argentina’s hydrocarbon
reserves, with the main purpose of satisfying domestic demand. However, on
January 5, 2007, Hydrocarbon Law 26.197 was passed by the Government of
Argentina. This new legal framework replaces article one of the Hydrocarbons Law
17.319 and provides for the provinces to assume complete ownership, authority
and administration of the crude oil and natural gas reserves located within
their territories, including offshore areas up to 12 marine miles from the coast
line. This includes all exploration, exploitation and transportation
concessions.
On June
3, 2002, the Argentine government issued a resolution authorizing the Energy
Secretariat to limit the amount of crude oil that companies can export. The
restriction was to be in place from June 2002 to September 2002. However, on
June 14, 2002, the government agreed to abandon the limit on crude export
volumes in exchange for a guarantee from oil companies that domestic demand will
be supplied. Oil companies also agreed not to raise natural gas and related
prices to residential customers during the winter months and to maintain
gasoline, natural gas and oil prices in line with those in other South American
countries.
Near the
end of 2007, the Argentine government issued decrees changing the withholding
tax structure and further regulating oil exports. The effects on Gran Tierra are
noted in “
Negative Economic,
Political and Regulatory Developments in Argentina, Including Export Controls,
May Negatively Affect our Operations
” in Item 1A “Risk
Factors”.
At the
end of 2008, the Argentine government launched the Gas Plus and Petroleum Plus
programs, new programs designed to stimulate investments in and production of
natural gas and oil through providing incentives for new production of natural
gas or oil, either from new discoveries, enhanced recovery techniques or
reactivation of older fields. Companies must apply for the incentives, and
qualification is based on a complex set of formulas involving increased
production over a calculated base and increases in proved reserves for the year.
Gran Tierra received credit under the Petroleum Plus program related to our
production for the fourth quarter of 2008. Gran Tierra did not qualify for
credit for oil production in 2009, however will continue to apply for credit
under each program as applicable.
Peru
Peru’s
hydrocarbon legislation, which includes the Organic Hydrocarbon Law No. 26221
and the regulations thereunder (the “Organic Hydrocarbon Law”), governs our
operations in Peru. This legislation covers the entire range of petroleum
operations, defines the roles of Peruvian government agencies which regulate and
interact with the oil and gas industry, requires that investments in the
petroleum sector be undertaken solely by private investors (either national or
foreign), and provides for the promotion of the development of hydrocarbon
activities based on free competition and free access to all economic activities.
This law provides that pipeline transportation and natural gas distribution must
be handled via contracts with the appropriate governmental authorities. All
other petroleum activities are to be freely operated and are subject only to
local and international safety and environment standards.
Under this legal system,
Peru is the owner of the hydrocarbons located below the surface in its national
territory. However, Peru has given the ownership right to extracted hydrocarbons
to Perupetro S.A. (Perupetro), a state company responsible for promoting and
overseeing the investment of hydrocarbon exploration and exploitation activities
in Peru. Perupetro is empowered to enter into contracts for either the
exploration and exploitation or just the exploitation of petroleum and natural
gas on behalf of Peru, the nature of which are described further below. The
Peruvian government also plays an active role in petroleum operations through
the involvement of the Ministry of Energy and Mines, the specialized government
department in charge of devising energy, mining and environmental protection
policies, enacting the rules applicable to all these sectors and supervising
compliance with such policies and rules. We are subject to the laws and
regulations of all of these entities and agencies.
Perupetro
generally enters into either license contracts or service contracts for
hydrocarbon exploration and exploitation. Peru’s laws also allow for other
contract models, but the investor must propose contract terms compatible with
Peru’s interests. We only operate under license contracts and do not foresee
operating under any services contracts. A company must be qualified by Perupetro
to enter into hydrocarbon exploration and exploitation contracts in Peru. In
order to qualify, the company must meet the standards under the Regulations
Governing the Qualifications of Oil Companies. These qualifications generally
require the company to have the technical, legal, economic and financial
capacity to comply with all obligations it will assume under the contract based
on the characteristics of the area requested, the possible investments and the
environmental protection rules governing the performance of its operations. When
a contractor is a foreign investor, it is expected to incorporate a subsidiary
company or registered branch in accordance with Peru’s corporate law and appoint
representatives in accordance with the Organic Hydrocarbon Law who will interact
with Perupetro.
Gran
Tierra has been qualified by Perupetro with respect to our current contracts.
However, Perupetro reviews the qualification for each specific contract to be
signed by a company. Additionally, the qualification for foreign companies is
granted in favor of the home office or corporation, which is jointly and
severally liable at all times for the technical, legal, economic and financial
capacity of its Peruvian subsidiary or branch.
When
operating under a license contract, the licensee is the owner of the
hydrocarbons extracted from the contract area during the performance of
operations, and pays royalties which are collected by Perupetro. The licensee
can market or export the hydrocarbons in any manner whatsoever, subject to a
limitation in the case of natural emergencies where the law stipulates such
manner.
10
Brazil
In
Brazil, law No. 2,004/53 instituted the state monopoly of the petroleum industry
and created Petróleo Brasileiro S.A (“Petrobras”), a corporation using public
and private funds under control of the Federal Union of Brazil (“Federal
Union”), to be the exclusive operator of exploration and production concessions
in Brazil.
Amendment
No. 9 to the Federal Constitution, issued on November 9, 1995, authorized the
Federal Union to execute contracts with state and private companies for the
exploration and production of oil and natural gas, as well as for the refining,
transportation, import and export of oil, natural gas and its by-products,
discontinuing Petrobras’ exclusive right to operate exploration and production
concessions in Brazil.
Oil and
natural gas located in Brazil, whether onshore or offshore, are the property of
the Federal Union. Under the principles of the Federal Constitution the national
territory comprises all land and the continental shelf. Brazil is a signatory of
the conventions regulating the economic use of the sea and its subsoil. Brazil
is thus entitled to the enjoyment of the resources over the territorial sea and
marine platform up to the limits indicated in the pertinent treaties. Part of
the revenues from the exploitation of the hydrocarbon resources collected by the
Federal Union is passed on to States and Municipalities.
The new
institutional and regulatory model is governed by Law No. 9,748/97, the
Petroleum Law, which controls the granting of concessions and authorization for
carrying out exploration and production activities to Brazilian companies, i.e.,
those created in accordance with Brazilian laws, with head offices and
management located within the national territory.
In
accordance with the Petroleum Law, the acquisition of oil and natural gas
property and oil and gas operations by state and private companies are subject
to legal, technical and economic standards and regulations issued by the
National Petroleum Agency (“ANP”), the agency created by the Petroleum Law and
vested with regulatory and inspection authority to ensure adequate operational
procedures with respect to industry activities and the supply of fuels
throughout the national territory.
ANP has
authority for the implementation of the national oil and natural gas policy. ANP
conducts bid rounds to award exploration, development and production contracts,
as well as to approve the construction and operation of refineries and gas
processing units, transportation facilities (including port terminals), import
and export of oil and natural gas, as well as supervision of the activities
which integrate the petroleum industry and the general enforcement of the
Petroleum Law.
The
granting of concession contracts is preceded by a public bid procedure,
regulated by ANP. Any company evidencing technical, financial and legal
standards under the applicable regulations may qualify and apply for particular
blocks made available for concession contracts at each licensing round.
Qualified companies may compete alone or in association with other companies,
including through the formation of “consortia” (unincorporated joint-ventures),
provided they agree to comply with all the applicable requirements of the
Brazilian Corporate Law. Blocks awarded and the duration of the exploration and
production periods are defined in the contracts which, besides the usual
covenants that can be found in oil concessions, such as exploration and
development programs, relinquishment of areas, and unitization, include
reversion to the state of certain assets at the end of the concession. Contracts
may be assigned/transferred to other Brazilian companies that comply with the
technical, financial and legal requirements established by ANP.
Concessionaires
are required under Law No. 9,478 to pay the government dues and fees, in
addition to the charges for sale of pre-bid data and information. ANP has the
power to determine the criteria under which the Government Take will be assessed
within the limits established by Decree No. 2,705/98. Government Take comprises
(i) signature bonus, (ii) royalties, (iii) special participation and (iv) area
rentals.
Gran
Tierra Energy Brasil, Ltda. is currently working on the necessary filings in
order to qualify as an operator of oil and natural gas concessions in
Brazil.
See Item
1A “Risk Factors” for information regarding the regulatory risks that we
face.
Environmental
Compliance
Our
activities are subject to existing laws and regulations governing environmental
quality and pollution control in the foreign countries where we maintain
operations. Our activities with respect to exploration, drilling and production
from wells, facilities, including the operation and construction of pipelines,
plants and other facilities for transporting, processing, treating or storing
crude oil and other products, are subject to stringent environmental regulation
by provincial and federal authorities in Colombia, Argentina and Peru. Such
regulations relate to environmental impact studies, permissible levels of air
and water emissions, control of hazardous wastes, construction of facilities,
recycling requirements, reclamation standards, among others. Risks are inherent
in oil and gas exploration, development and production operations, and
significant costs and liabilities may be incurred in connection with
environmental compliance issues. All licenses and permits which we may require
to carry out exploration and production activities may not be obtainable on
reasonable terms or on a timely basis, and such laws and regulations may have an
adverse effect on any project that we may wish to undertake.
11
In 2010,
we plan to spend approximately $3.6 million in Colombia on capital programs
related to environmental matters, including facilities upgrades, studies,
assessments and remediation. We plan to spend approximately $150,000 in
Argentina on capital programs related to environmental matters, including
environmental studies and fire system upgrades. In Peru, capital costs for
environmental projects will be about $1.6 million.
In 2009,
we experienced a limited number of environmental incidents and enacted many
environmental initiatives as follows:
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In
Colombia, we dealt with several
incidents:
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In
February 2009, there was a fire at our Juanambu-1 well that occurred
during operations related to maintenance on a generator. Approximately six
barrels of oil were spilled and clean up costs were approximately $6,000.
Total damage to equipment was estimated at $500,000, and production valued
at approximately $125,000 was deferred due to shutting down production
facilities while dealing with the
incident.
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A
number of small incidents on our blocks occurred during the year, each of
which causing small quantities of oil to be spilled. In each incident Gran
Tierra completed a full clean up and remediation of the affected area.
Total barrels lost to these incidents were approximately 170 barrels and
clean up costs totaled approximately
$30,000.
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In
Argentina, a contracted transportation provider had two incidents while
transporting Gran Tierra’s oil. In March 2009, a tanker overturned during
an accident and a small quantity of hydrocarbons (approximately 10
barrels) was spilled. In July 2009, a subcontractor of the same service
provider had an accident with a cyclist while transporting Gran Tierra’s
oil. We suspended our contract with the transportation provider following
the second incident and contracted the services of another transportation
company.
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We
have a Corporate Health, Safety and Environment Management System and
follow Environmental Best Practices. We have an environmental risk
management program in place as well as a waste management system. Air and
water testing occur regularly, and environmental contingency plans have
been prepared for all sites and ground transportation of crude oil. We
implemented a regular quarterly comprehensive reporting system in 2009,
and continue with a schedule of internal audit and routine checking of
practices and procedures.
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In
Peru, we completed the process of conducting an EIA on each of our blocks.
The costs for 2009 for these EIAs were approximately $945,000, with total
costs to date totaling about $1.6 million. We have also made contributions
to PROCREL, a local non-governmental organization that works on
conservation programs, biodiversity and sustainable development in
Peru.
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We will
continue to strive to be in compliance with all environmental and pollution
control laws and regulations in Colombia, Argentina and Peru. We plan to
continue enacting environmental, health and safety initiatives in order to
minimize our environmental impact and expenses. We also plan to continue and
improve internal audit procedures and practices in order to monitor current
performance and search for improvement.
We expect
the cost of compliance with Federal, State and local provisions which have been
enacted or adopted regulating the discharge of materials into the environment,
or otherwise relating to the protection of the environment for the remainder of
our operations, will not be material to our company.
Community
Relations
In 2009,
we commenced standardized, quarterly reporting on our community relations
initiatives. We also continuously monitor the needs of the communities we
operate in to ensure that our investments meet their requirements and have the
highest impact possible.
In
addition to employing local people and hiring local companies as often as
feasible in all of our operations, we have a program of community investment in
all of our operating areas. Projects completed in 2009 are as
follows:
Colombia
Gran
Tierra invested approximately $500,000 in many projects in our operating areas
as outlined below:
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Provided
support for education through various projects, including providing
tuition, supplies, transportation and construction of facilities for
students in all levels of
education.
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Supported
community groups in projects that benefited local families with
agriculture and fisheries projects. We provided fiscal support,
construction of facilities, transportation of materials and other
expertise to the projects.
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Various
projects for the support of cultural identity such as sponsorship of local
festivals that celebrate indigenous culture and history; construction of a
workshop for local artisans and community centers; sponsorship of local
people to attend a conference of indigenous people from various areas in
the country; another sponsorship for delegates to a national conference of
community associations; purchase of an FM radio transmitter for one area
to allow communities in the area to connect; support for the improvement
of local churches; and providing Christmas gifts to children of local
communities.
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Various
programs for strengthening local infrastructure such as road and bridge
construction, canalization of part of the River Mocoa to protect a local
port, and materials and other resources for
electrification.
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Projects
related to health, basic sanitation and housing including improving health
facilities, providing supplies to health facilities, providing materials
for house construction, constructing community kitchens and community
centres, and finally completion of the first stage of construction of a
local fire station.
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Programs
supporting sport and recreation such as constructing sport complexes and
playgrounds in various districts, sponsoring sports camps, and providing
equipment.
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Argentina
In
Argentina we invested approximately $43,000 in the following
projects:
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A
partnership with the organization Voces y Ecos (Voices and Echoes) to
distribute education materials.
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Provided
basic life necessities (food, clothing) to impoverished people in our
operating areas.
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Provided
funds for the purchase of clothing for the communities in our area of
operations.
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Along
with our joint venture partners in the Palmar Largo block, several other
initiatives were undertaken, including projects aimed at developing
sustainable incomes for the communities in the area; fuel and security for
local hospitals; and construction of reservoirs and water wells. These
projects were operated by
PlusPetrol.
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Peru
In Peru,
we conducted community consultation and education sessions held with various
communities located on our two blocks. Costs for these programs are included in
the costs above related to the EIA’s for Peru. Representatives of Gran Tierra
attended sessions with local residents to provide information on the operations
we will conduct during our exploration program, and also to gather information
from the residents on the needs in the areas. In addition to the EIA work, we
spent approximately $30,000 on other initiatives.
Employees
At
December 31, 2009, we had 269 full-time employees — 21 located in the Calgary
corporate office, 209 in Colombia (99 staff in Bogota and 110 field personnel),
35 in Argentina (18 office staff in Buenos Aires and 17 field personnel), two in
Peru (both field and office staff) and two in Brazil, both office staff. None of
our employees are represented by labor unions, and we consider our employee
relations to be good.
Risks Related to Our Business
Our Lack of
Diversification Will Increase the Risk of an Investment in Our Common
Stock.
Our
business focuses on the oil and gas industry in a limited number of properties
in Colombia, Argentina and Peru, and we have opened a development office in
Brazil. Most of our production in Colombia and Argentina is limited to one basin
per country. As a result, we lack diversification, in terms of both the nature
and geographic scope of our business. Accordingly, factors affecting our
industry or the regions in which we operate, including the geographic remoteness
of our operations and weather conditions, will likely impact us more acutely
than if our business was more diversified.
13
We May Encounter
Difficulties Storing and Transporting Our Production, Which Could Cause a
Decrease in Our Production or an Increase in Our Expenses.
To sell
the oil and natural gas that we are able to produce, we have to make
arrangements for storage and distribution to the market. We rely on local
infrastructure and the availability of transportation for storage and shipment
of our products, but infrastructure development and storage and transportation
facilities may be insufficient for our needs at commercially acceptable terms in
the localities in which we operate. This could be particularly problematic to
the extent that our operations are conducted in remote areas that are difficult
to access, such as areas that are distant from shipping and/or pipeline
facilities. In certain areas, we may be required to rely on only one gathering
system, trucking company or pipeline, and, if so, our ability to market our
production would be subject to their reliability and operations. These factors
may affect our ability to explore and develop properties and to store and
transport our oil and gas production, and may increase our
expenses.
Furthermore,
future instability in one or more of the countries in which we 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.
The
majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol
and sales of oil could be disrupted by damage to this pipeline. Once delivered
to Ecopetrol, all of our current oil production in Colombia is transported by an
export pipeline which provides the only access to markets for our oil. Problems
on these pipelines can cause interruptions to our producing activities if they
are for a long enough duration that our storage facilities become full. For
example, we experienced disruptions in transportation on this pipeline in March
and April of 2008, and again in each of June, July and August of 2009, as a
result of sabotage by guerrillas. In addition, there is competition for space in
these pipelines, and additional discoveries in our area of operations by other
companies could decrease the pipeline capacity available to us. Trucking is an
alternative to transportation by pipeline, however it is generally more
expensive and carries higher safety risks for the company and the
public.
As the
majority of current oil production in Argentina is trucked to a local refinery,
sales of oil can be delayed by adverse weather and road conditions, particularly
during the months November through February when the area is subject to periods
of heavy rain and flooding. While storage facilities are designed to accommodate
ordinary disruptions without curtailing production, delayed sales will delay
revenues and may adversely impact our working capital position in Argentina.
Furthermore, a prolonged disruption in oil deliveries could exceed storage
capacities and shut-in production, which could have a negative impact on future
production capability.
Guerrilla
Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned
About Safeguarding Our Operations and Personnel in Colombia.
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
operate principally in the Putumayo basin in Colombia, and have properties in
other basins, including the Catatumbo, Llanos, Middle Magdalena and Lower
Magdalena basins. The Putumayo and Catatumbo regions have been prone to guerilla
activity in the past. In 1989,our predecessor company’s facilities in one field
were attacked by guerillas and operations were briefly disrupted. Pipelines have
also been targets, including the Ecopetrol - operated Trans Andean export
pipeline which transports oil from the Putumayo region. In March and April of
2008, and again in each of June, July, August and October of 2009, sections of
the Trans Andean pipeline were blown up by guerillas, which temporarily reduced
our deliveries to Ecopetrol during the effected periods.
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 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 an executive management team
consisting of Dana Coffield, our President and Chief Executive Officer, Martin
Eden, our Vice President, Finance and Chief Financial Officer, Shane O’Leary,
our Chief Operating Officer, Rafael Orunesu, our President of Gran Tierra
Argentina SA, Julian Garcia, our President of Gran Tierra Colombia, and Julio
Moreira, our President of Gran Tierra Brazil. The loss of any of these
individuals or our inability to attract suitably qualified individuals to
replace any of them could materially adversely impact our business. We may also
experience difficulties in certain jurisdictions in our efforts to obtain
suitably qualified staff and retain staff that are willing to work in that
jurisdiction. We do not currently carry life insurance for our key
employees.
14
Our
success depends on the ability of our management and employees to interpret
market and geological data successfully and to interpret and respond to
economic, market and other business conditions in order to locate and adopt
appropriate investment opportunities, monitor such investments and ultimately,
if required, successfully divest such investments. Further, our key personnel
may not continue their association or employment with Gran Tierra and we may not
be able to find replacement personnel with comparable skills. If we are unable
to attract and retain key personnel, our business may be adversely affected.
Our Oil Sales
Will Depend on a Relatively Small Group of Customers, Which Could Adversely
Affect Our Financial Results.
Oil sales
in Colombia are 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 one
customer. The lack of competition in this market could result in unfavorable
sales terms which, in turn, could adversely affect our financial results.
Currently all operators in Argentina are operating without sales contracts. We
cannot provide any certainty as to when the situation will be resolved or what
the final outcome will be.
Strategic
Relationships Upon Which We May Rely are Subject to Change, Which May Diminish
Our Ability to Conduct Our Operations.
Our
ability to successfully bid on and acquire additional properties, to discover
reserves, to participate in drilling opportunities and to identify and enter
into commercial arrangements will depend on developing and maintaining effective
working relationships with industry participants and on our ability to select
and evaluate suitable 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, in cases where we are the operator, our partners may not be able to
fulfill their obligations, which would require us to either take on their
obligations in addition to our own, or possibly forfeit our rights to the area
involved in the joint venture. Alternatively, our partners may be able to
fulfill their obligations, but will not agree with our proposals as operator of
the property. In this case there could be disagreements between joint venture
partners that could be costly in terms of dollars, time, deterioration of the
partner relationship, and/or our reputation as a competent operator.
In cases
where we are not the operator of the joint venture, the success of the projects
held under these joint ventures is substantially dependent on our joint venture
partners. The operator is responsible for day to day operations, safety,
environmental compliance and relationships with government and
vendors.
We have
various work obligations on our blocks that must be fulfilled or we could face
penalties, or lose our rights to those blocks if we do not fulfill our work
obligations. Failure to fulfill obligations in one block can also have
implications on the ability to operate other blocks in the country ranging from
delays in government process and procedure to loss of rights in other blocks or
in the country as a whole. Failure to meet obligations in one particular country
may also have an impact on our ability to operate in others.
Our Business is
Subject to Local Legal, Political and Economic Factors Which are Beyond Our
Control, Which Could Impair Our Ability to Expand Our Operations or Operate
Profitably.
We
operate our business in Colombia, Argentina and Peru, have opened an in-country
office in Brazil to expand our operations into that country and may eventually
expand to other countries in the world. Exploration and production operations in
foreign countries are subject to legal, political and economic uncertainties,
including terrorism, military repression, social unrest, strikes by local or
national labor groups, interference with private contract rights (such as
privatization), extreme fluctuations in currency exchange rates, high rates of
inflation, exchange controls, changes in tax rates, changes in laws or policies
affecting environmental issues (including land use and water use), workplace
safety, foreign investment, foreign trade, investment or taxation, as well as
restrictions imposed on the oil and natural gas industry, such as restrictions
on production, price controls and export controls. For example, starting on
November 21, 2008, we were forced to reduce production in Colombia on a gradual
basis, culminating on December 11, 2008 when we suspended all production from
the Santana, Guayuyaco and Chaza blocks in the Putumayo Basin. This temporary
suspension of production operations was the result of a declaration of a state
of emergency and force majeure by Ecopetrol due to a general strike in the
region. In January 2009, the situation was resolved and we were able to resume
production and sales shipments.
15
South
America has a history of political and economic instability. This instability
could result in new governments or the adoption of new policies, laws or
regulations that might assume a substantially more hostile attitude toward
foreign investment, including the imposition of additional taxes. In an extreme
case, such a change could result in termination of contract rights and
expropriation of foreign-owned assets. Any changes in oil and gas or investment
regulations and policies or a shift in political attitudes in Argentina,
Colombia, Peru or Brazil or other countries in which we intend to operate are
beyond our control and may significantly hamper our ability to expand our
operations or operate our business at a profit.
For
instance, changes in laws in the jurisdiction in which we operate or expand into
with the effect of favoring local enterprises, and changes in political views
regarding the exploitation of natural resources and economic pressures, may make
it more difficult for us to negotiate agreements on favorable terms, obtain
required licenses, comply with regulations or effectively adapt to adverse
economic changes, such as increased taxes, higher costs, inflationary pressure
and currency fluctuations. In certain jurisdictions the commitment of local
business people, government officials and agencies and the judicial system to
abide by legal requirements and negotiated agreements may be more uncertain,
creating particular concerns with respect to licenses and agreements for
business. These licenses and agreements may be susceptible to revision or
cancellation and legal redress may be uncertain or delayed. Property right
transfers, joint ventures, licenses, license applications or other legal
arrangements pursuant to which we operate may be adversely affected by the
actions of government authorities and the effectiveness of and enforcement of
our rights under such arrangements in these jurisdictions may be
impaired.
Foreign Currency
Exchange Rate Fluctuations May Affect Our Financial Results.
We expect
to sell our oil and natural gas production under agreements that will be
denominated in United States dollars and foreign currencies. Many of the
operational and other expenses we incur will be paid in the local currency of
the country where we perform our operations. Our production 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
3.94 pesos to the US dollar, a fluctuation of approximately 29%. Exchange rates
between the Colombian peso and US dollar have varied between 2,632 pesos to one
US dollar to 1,648 pesos to one US dollar since September 1, 2005, a fluctuation
of approximately 60%.
In
addition, a foreign exchange loss of $17.7 million, of which $17.4 million is an
unrealized non-cash foreign exchange loss, was recorded in 2009 primarily due to
the translation of a deferred tax liability recorded on the purchase of Solana.
The deferred tax liability is denominated in Colombian pesos and the devaluation
of 9% in the US dollar against the Colombian Peso in 2009 resulted in the
foreign exchange loss.
Exchange Controls
and New Taxes Could Materially Affect our Ability to Fund Our Operations and
Realize Profits from Our Foreign Operations.
Foreign
operations may require funding if their cash requirements exceed operating cash
flow. To the extent that funding is required, there may be exchange controls
limiting such funding or adverse tax consequences associated with such funding.
In addition, taxes and exchange controls may affect the dividends that we
receive from foreign subsidiaries.
Exchange
controls may prevent us from transferring funds abroad. For example, the
Argentine government has imposed a number of monetary and currency exchange
control measures that include restrictions on the free disposition of funds
deposited with banks and tight restrictions on transferring funds abroad, with
certain exceptions for transfers related to foreign trade and other authorized
transactions approved by the Argentine Central Bank. The Central Bank may
require prior authorization and may or may not grant such authorization for our
Argentine subsidiaries to make dividend payments to us and there may be a tax
imposed with respect to the expatriation of the proceeds from our foreign
subsidiaries.
Competition in
Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our
Production May Impair Our Business.
The oil
and gas industry is highly competitive. Other oil and gas companies will compete
with us by bidding for exploration and production licenses and other properties
and services we will need to operate our business in the countries in which we
expect to operate. Additionally, other companies engaged in our line of business
may compete with us from time to time in obtaining capital from investors.
Competitors include larger, foreign owned companies, which, in particular, may
have access to greater resources than us, may be more successful in the
recruitment and retention of qualified employees and may conduct their own
refining and petroleum marketing operations, which may give them a competitive
advantage. In addition, actual or potential competitors may be strengthened
through the acquisition of additional assets and interests. In the event that we
do not succeed in negotiating additional property acquisitions, our future
prospects will likely be substantially limited, and our financial condition and
results of operations may deteriorate.
16
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 lack many resources taken for granted in North America. The
opportunities for investment are large, many and varied; however, we must be
careful to invest carefully in projects that will truly benefit these areas.
Improper management of these investments and relationships could lead to a delay
in operations, loss of license or major impact to our reputation in these
communities, which could adversely affect our business.
Our Operations
Involve Substantial Costs and are Subject to Certain Risks Because the Oil and
Gas Industries in the Countries in Which We Operate are Less Developed.
The oil
and gas industry in South America is not as efficient or developed as the oil
and gas industry in North America. As a result, our exploration and development
activities may take longer to complete and may be more expensive than similar
operations in North America. The availability of technical expertise, specific
equipment and supplies may be more limited than in North America. We expect that
such factors will subject our international operations to economic and operating
risks that may not be experienced in North American operations.
Negative
Political and Regulatory Developments in Argentina May Negatively Affect our
Operations.
The crude
oil and natural gas industry in Argentina is subject to extensive regulation
including land tenure, exploration, development, production, refining,
transportation, and marketing, imposed by legislation enacted by various levels
of government and, with respect to pricing and taxation of crude oil and natural
gas, by agreements among the federal and provincial governments, all of which
are subject to change and could have a material impact on our business in
Argentina. The Federal Government of Argentina has implemented controls for
domestic fuel prices and has placed a tax on crude oil and natural gas
exports.
Any
future regulations that limit the amount of oil and gas that we could sell or
any regulations that limit price increases in Argentina and elsewhere could
severely limit the amount of our revenue and affect our results of
operations.
Currently
most oil and gas producers in Argentina are operating without sales contracts.
In 2008, a new withholding tax regime for exports was introduced without
specific guidance as to its application. The domestic price was regulated in a
similar way, so that both exported and domestically sold products were priced
the same. Producers and refiners of oil in Argentina were unable to determine an
agreed sales price for oil deliveries to refineries. Also, the price for
refiners’ gasoline production was 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 one, Refiner S.A., and the price is negotiated on a month by month
basis. From January to May 2009, we delivered two truckloads per day to
Polipetrol in Mendoza province, and that price was negotiated weekly. We stopped
delivering to Polipetrol in May 2009, due to possible financial problems at the
refinery. The Provincial Governments have also been hurt by these changes as
their effective royalty take has been reduced and capital investment in
oilfields has declined, and so they are lobbying to change the situation. We are
working with other oil and gas producers in the area, as well as Refiner S.A.,
to lobby the federal government for change. The government introduced the Petro
Plus and Gas Plus programs in 2009, which grant higher prices to producers that
sell production from new reserves. This is a positive step forward that will
hopefully lead to further opening of price regulation in Argentina.
The United States
Government May Impose Economic or Trade Sanctions on Colombia That Could Result
In A Significant Loss To Us.
Colombia
is among several nations whose eligibility to receive foreign aid from the
United States is dependent on its progress in stemming the production and
transit of illegal drugs, which is subject to an annual review by the President
of the United States. Although Colombia is currently eligible for such aid,
Colombia may not remain eligible in the future. A finding by the President that
Colombia has failed demonstrably to meet its obligations under international
counternarcotics agreements may result in any of the following:
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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.
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Each of
these consequences could result in adverse economic consequences in Colombia and
could further heighten the political and economic risks associated with our
operations there. Any changes in the holders of significant government offices
could have adverse consequences on our relationship with ANH and Ecopetrol and
the Colombian government’s ability to control guerrilla activities and could
exacerbate the factors relating to our foreign operations. Any sanctions imposed
on Colombia by the United States government could threaten our ability to obtain
necessary financing to develop the Colombian properties or cause Colombia to
retaliate against us, including by nationalizing our Colombian assets.
Accordingly, the imposition of the foregoing economic and trade sanctions on
Colombia would likely result in a substantial loss and a decrease in the price
of our common stock. The United States may impose sanctions on Colombia in the
future, and we cannot predict the effect in Colombia that these sanctions might
cause.
17
We May Be Unable
to Obtain Additional Capital That We Will Require to Implement Our Business
Plan, Which Could Restrict Our Ability to Grow.
We expect
that our existing cash and credit resources will be sufficient to fund our
currently planned activities. We may require additional capital to expand our
exploration and development programs to additional properties. We may be unable
to obtain additional capital required.
When we
require additional capital we plan to pursue sources of capital through various
financing transactions or arrangements, including joint venturing of projects,
debt financing, equity financing or other means. We may not be successful in
locating suitable financing transactions in the time period required or at all,
and we may not obtain the capital we require by other means. 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
results.
Our
ability to obtain needed financing may be impaired by factors such as the
capital markets (both generally and in the oil and gas industry in particular),
the location of our oil and natural gas properties in South America, prices of
oil and natural gas on the commodities markets (which will impact the amount of
asset-based financing available to us), and/or the loss of key management.
Further, if oil and/or natural gas prices on the commodities markets decrease,
then our revenues will likely decrease, and such decreased revenues may increase
our requirements for capital. Some of the contractual arrangements governing our
exploration activity may require us to commit to certain capital expenditures,
and we may lose our contract rights if we do not have the required capital to
fulfill these commitments. If the amount of capital we are able to raise from
financing activities, together with our cash flow from operations, is not
sufficient to satisfy our capital needs (even to the extent that we reduce our
activities), we may be required to cease our operations.
We May Not Be
Able To Effectively Manage Our Growth, Which May Harm Our Profitability.
Our
strategy envisions continually 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.
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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.
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.
18
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 make
estimates of oil and natural gas reserves, upon which we will base our financial
projections. We make these reserve estimates using various assumptions,
including assumptions as to oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. Some of these
assumptions are inherently subjective, and the accuracy of our reserve estimates
relies in part on the ability of our management team, engineers and other
advisors to make accurate assumptions. Economic factors beyond our control, such
as interest rates and exchange rates, will also impact the value of our
reserves. The process of estimating oil and gas reserves is complex, and will
require us to use significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
property. As a result, our reserve estimates will be inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves may vary substantially from those we estimate. If actual
production results vary substantially from our reserve estimates, this could
materially reduce our revenues and result in the impairment of our oil and
natural gas interests.
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.
19
If
Oil and Natural Gas Prices Decrease, We May be Required to Take Write-Downs of
the Carrying Value of Our Oil and Natural Gas Properties.
We follow
the full cost method of accounting for our oil and gas properties. A separate
cost center is maintained for expenditures applicable to each country in which
we conduct exploration and/or production activities. Under this method, the net
book value of properties on a country-by-country basis, less related deferred
income taxes, may not exceed a calculated “ceiling”. The ceiling is the
estimated after tax future net revenues from proved oil and gas properties,
discounted at 10% per year. In calculating discounted future net revenues, oil
and natural gas prices are determined using the average price during the 12
months period prior to the ending date of the period covered by the balance
sheet, calculated as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such period for that oil and
natural gas. That average price is then held constant, except for changes which
are fixed and determinable by existing contracts. The net book value is compared
to the ceiling on a quarterly basis. The excess, if any, of the net book value
above the ceiling is required to be written off as an expense. Under full cost
accounting rules, any write-off recorded may not be reversed even if higher oil
and natural gas prices increase the ceiling applicable to future periods. Future
price decreases could result in reductions in the carrying value of such assets
and an equivalent charge to earnings.
Drilling New
Wells and Producing Oil and Natural Gas from Existing Facilities Could Result in
New Liabilities, Which Could Endanger Our Interests in Our Properties and
Assets.
There are
risks associated with the drilling of oil and natural gas wells, including
encountering unexpected formations or pressures, premature declines of
reservoirs, blow-outs, craterings, sour gas releases, fires and spills.
Earthquakes or weather related phenomena such has heavy rain, landslides, storms
and hurricanes can also cause problems in drilling new wells. There are also
risks in producing oil and natural gas from existing facilities. For example, on
February 7, 2009 we experienced an incident at our Juanambu 1 well, involving a
fire in a generator, resulting in total damage to equipment estimated at
$500,000, and production in the amount of approximately $125,000 being deferred
due to shutting down production facilities while dealing with the incident. The
occurrence of any of these events could significantly reduce our revenues or
cause substantial losses, impairing our future operating results. We may become
subject to liability for pollution, blow-outs or other hazards. Incidents such
as these can lead to serious injury, property damage and even loss of life. We
generally obtain insurance with respect to these hazards, but such insurance has
limitations on liability that may not be sufficient to cover the full extent of
such liabilities. The payment of such liabilities could reduce the funds
available to us or could, in an extreme case, result in a total loss of our
properties and assets. Moreover, we may not be able to maintain adequate
insurance in the future at rates that are considered reasonable. Oil and natural
gas production operations are also subject to all the risks typically associated
with such operations, including premature decline of reservoirs and the invasion
of water into producing formations.
Our Inability to
Obtain Necessary Facilities and/or Equipment Could Hamper Our Operations.
Oil and
natural gas exploration and development activities are dependent on the
availability of drilling and related equipment, transportation, power and
technical support in the particular areas where these activities will be
conducted, and our access to these facilities may be limited. To the extent that
we conduct our activities in remote areas, needed facilities or equipment may
not be proximate to our operations, which will increase our expenses. Demand for
such limited equipment and other facilities or access restrictions may affect
the availability of such equipment to us and may delay exploration and
development activities. The quality and reliability of necessary facilities or
equipment may also be unpredictable and we may be required to make efforts to
standardize our facilities, which may entail unanticipated costs and delays.
Shortages and/or the unavailability of necessary equipment or other facilities
will impair our activities, either by delaying our activities, increasing our
costs or otherwise.
Decommissioning
Costs Are Unknown and May be Substantial; Unplanned Costs Could Divert Resources
from Other Projects.
We may
become responsible for costs associated with abandoning and reclaiming wells,
facilities and pipelines which we use for production of oil and gas reserves.
Abandonment and reclamation of these facilities and the costs associated
therewith is often referred to as “decommissioning.” We have determined that we
require a reserve account for these potential costs in respect of our current
properties and facilities at this time, and have booked such reserve on our
financial statements. If decommissioning is required before economic depletion
of our properties or if our estimates of the costs of decommissioning exceed the
value of the reserves remaining at any particular time to cover such
decommissioning costs, we may have to draw on funds from other sources to
satisfy such costs. The use of other funds to satisfy decommissioning costs
could impair our ability to focus capital investment in other areas of our
business.
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 2009 was $61.83, 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.
20
In
addition, oil and natural gas prices in Argentina are effectively regulated and
during 2009 were substantially lower than those received in North America. Oil
prices in Colombia are related to international market prices, but adjustments
that are defined by contract with Ecopetrol, the purchaser of most of the oil
that we produce in Colombia, may cause realized prices to be lower than those
received in North America.
Penalties We May
Incur Could Impair Our Business.
Our
exploration, development, production and marketing operations are regulated
extensively under foreign, federal, state and local laws and regulations. Under
these laws and regulations, we could be held liable for personal injuries,
property damage, site clean-up and restoration obligations or costs and other
damages and liabilities. We may also be required to take corrective actions,
such as installing additional safety or environmental equipment, which could
require us to make significant capital expenditures. Failure to comply with
these laws and regulations may also result in the suspension or termination of
our operations and subject us to administrative, civil and criminal penalties,
including the assessment of natural resource damages. We could be required to
indemnify our employees in connection with any expenses or liabilities that they
may incur individually in connection with regulatory action against them. As a
result of these laws and regulations, our future business prospects could
deteriorate and our profitability could be impaired by costs of compliance,
remedy or indemnification of our employees, reducing our
profitability.
Policies,
Procedures and Systems to Safeguard Employee Health, Safety and Security May Not
be Adequate.
Oil and
natural gas exploration and production is dangerous. Detailed and specialized
policies, procedures and systems are required to safeguard employee health,
safety and security. We have undertaken to implement best practices for employee
health, safety and security; however, if these policies, procedures and systems
are not adequate, or employees do not receive adequate training, the
consequences can be severe including serious injury or loss of life, which could
impair our operations and cause us to incur significant legal
liability.
Environmental
Risks May Adversely Affect Our Business.
All
phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
international conventions and federal, provincial and municipal laws and
regulations. Environmental legislation provides for, among other things,
restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned
and reclaimed to the satisfaction of applicable regulatory authorities.
Compliance with such legislation can require significant expenditures and a
breach may result in the imposition of fines and penalties, some of which may be
material. Environmental legislation is evolving in a manner we expect may result
in stricter standards and enforcement, larger fines and liability and
potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise
to liabilities to foreign governments and third parties and may require us to
incur costs to remedy such discharge. The application of environmental laws to
our business may cause us to curtail our production or increase the costs of our
production, development or exploration activities.
Our Insurance May
Be Inadequate to Cover Liabilities We May Incur.
Our
involvement in the exploration for and development of oil and natural gas
properties may result in our becoming subject to liability for pollution,
blow-outs, property damage, personal injury or other hazards. Although we have
insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the
full extent of such liabilities. In addition, such risks may not, in all
circumstances be insurable or, in certain circumstances, we may choose not to
obtain insurance to protect against specific risks due to the high premiums
associated with such insurance or for other reasons. The payment of such
uninsured liabilities would reduce the funds available to us. If we suffer a
significant event or occurrence that is not fully insured, or if the insurer of
such event is not solvent, we could be required to divert funds from capital
investment or other uses towards covering our liability for such
events.
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.
21
If our
property rights are reduced, whether by governmental action or third party
challenges, our ability to conduct our exploration, development and production
may be impaired.
We Will Rely on
Technology to Conduct Our Business and Our Technology Could Become Ineffective
Or Obsolete.
We rely
on technology, including geographic and seismic analysis techniques and economic
models, to develop our reserve estimates and to guide our exploration and
development and production activities. We will be required to continually
enhance and update our technology to maintain its efficacy and to avoid
obsolescence. The costs of doing so may be substantial, and may be higher than
the costs that we anticipate for technology maintenance and development. If we
are unable to maintain the efficacy of our technology, our ability to manage our
business and to compete may be impaired. Further, even if we are able to
maintain technical effectiveness, our technology may not be the most efficient
means of reaching our objectives, in which case we may incur higher operating
costs than we would were our technology more efficient.
Risks Related to Our Common
Stock
The Market Price
of Our Common Stock May Be Highly Volatile and Subject to Wide
Fluctuations.
The
market price of our common stock may be highly volatile and could be subject to
wide fluctuations in response to a number of factors that are beyond our
control, including but not limited to:
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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.
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In
addition, the market price of our common stock could be subject to wide
fluctuations in response to various factors, which could include the following,
among others:
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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.
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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.
22
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.
Not
applicable.
Offices
We
currently lease office space in: Calgary, Alberta; Buenos Aires and Vespucio,
Argentina; Bogota, Colombia; Rio de Janiero, Brazil; and Lima and Iquitos, Peru.
We have five Calgary leases, the first two expire January 31, 2013, the third
expires October 31, 2012, the fourth expires April 30, 2014 and the fifth
expires October 30, 2015. They cost $11,695 per month, $6,312 per month, $3,884
per month, $12,568 per month and $32,577 per month, respectively. We have
subleased the fourth lease for $10,500 per month from February 1, 2009 to August
31, 2011, and we plan on subleasing the first three as well. All Calgary based
staff will be housed in the space covered by our fifth lease in March 2010. Our
two Buenos Aires, Argentina leases expire January 31, 2012 and July 17, 2012 and
cost $2,877 per month and $2,743 per month, respectively. The lease in Vespucio,
Argentina expires February 28, 2011 at a cost of $1,500 per month. We have four
leases in Bogota, Colombia. They expire February 28, 2010, April 1, 2010, June
30, 2010 and February 1, 2012 and cost $2,734 per month, $1,863 per month, 2,610
per month and $71,471 per month, respectively. We have office space leased in
Rio de Janiero, Brazil until September 30, 2012 at a cost of $5,380 per month.
In Lima, Peru, we have one office with a lease expiring October 31, 2010 at a
cost of $3,045 per month and a house for staff residence with a lease expiring
November 13, 2010 at a cost of $1,650 per month. In Iquitos, Peru we have a
combination office and staff residence with a lease expiring October 31, 2011 at
a cost of $1,055 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 the Santana,
Guayuyaco, Chaza and Mecaya blocks in the Putumayo basin in southwest Colombia;
the Talora and Rio Magdalena blocks in the Magdalena basin, west of Bogota; and
the Primavera block in the Llanos basin. The acquisition price included
overriding royalty rights and net profits interests in the blocks that were
owned by Argosy at the time of the acquisition. The Azar block in the Putumayo
basin was acquired later in 2006, and two Technical Evaluation Areas in the
Putumayo basin (Putumayo West A and Putumayo West B) were acquired in 2007. We
relinquished the Primavera block in 2007.
In
November 2008, we acquired Solana which increased our interest in the Guayuyaco
and Chaza blocks, and added 7 blocks in 3 basins. The Magangue Block is located
in the Lower Magdalena basin in northwest Colombia; the Catguas Block is in the
Catatumbo basin which forms the southwest flank of Venezuela’s Maracaibo basin;
and the Guachiria Norte, San Pablo, Guachiria, Guachiria Sur and Garibay blocks
are in the Llanos basin north east of Bogota.
In 2009
we converted portions of the two Technical Evaluation Areas
to three exploration and
production blocks – part of Putumayo West A was converted to two exploration and
exploitation blocks named Piedemonte Norte and Piedemonte Sur. Part of Putumayo
West B was converted to the Rumiyaco block. We sold the Guachria, Guachira Sur
and Guachira Norte blocks. We relinquished our rights to the San Pablo block and
Talora Blocks, and have entered into letters of intent regarding the sale of the
Catguas and Garibay blocks. We also entered into a sale agreement for the Rio
Magdalena and Mecaya blocks that is awaiting ANH approval.
Currently,
the Guayuyaco, Santana, and Chaza blocks have producing oil wells.
23
Colombian
royalties are set by law – specifically law 756 of 2002. All discoveries after
the enactment of this law have the sliding scale royalty described below.
Discoveries made before the enactment of this law have a royalty of 20%. The ANH
contracts to which Gran Tierra is a party all have royalties that are based on a
sliding scale described in law 756. This royalty works on an individual field
basis starting with a base royalty rate of 8% for gross production of less than
5,000 barrels of oil per day. The royalty increases in a linear fashion from 8%
to 20% for gross production between 5,000 and 125,000 barrels of oil per day,
and is stable at 20% for gross production between 125,000 and 400,000 barrels of
oil per day. For gross production between 400,000 and 600,000 barrels of oil per
day the rate increases in a linear fashion from 20% to 25%. For gross production
in excess of 600,000 barrels of oil per day the royalty rate is fixed at 25%.
Our production from our Costayaco field is also subject (starting in October
2009) to 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. As the law stands currently, any new discoveries on ANH
contracted blocks will also be subject to this additional royalty. Santana and
Magangue blocks have a flat 20% royalty; as those discoveries were made before
2002. Guayuyaco and Rio Magdalena blocks have the sliding scale royalty but do
not have the additional royalty. In addition to these government royalties, Gran
Tierra’s original interests in the five blocks purchased from Argosy that we
still hold (Santana, Guayuyaco, Chaza, Rio Magdalena, Mecaya) are subject to a
third party royalty. The additional interest in Guayuyaco and Chaza acquired by
Gran Tierra on the acquisition of Solana is not subject to this third party
royalty.
Santana
The
Santana block contract was signed in July 1987 and covers 1,119 acres and
includes 15 producing wells in four fields — Linda, Mary, Miraflor and Toroyaco.
Activities are governed by terms of a Shared Risk Contract with Ecopetrol, and
we are the operator. We hold a 35% working interest in all fields. Ecopetrol
holds the remaining interest. The block has been producing since 1991. Under the
Shared Risk Contract, Ecopetrol initially backed in to a 50% working interest
upon declaration of commerciality in 1991. In June 1996, when the 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 2009,
we performed regular facility and well maintenance. For 2010, we plan more of
the same.
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 2009,
we completed work on the separator for the Juanambu field and work on water
treatment facilities. In 2010, we plan to drill a second well in the Juanambu
field, drill an exploration well, and acquire 40 square kilometers of 3D
seismic. We also plan work on electrical systems, flowlines, storage tanks and
other facilities.
Chaza
The Chaza
block covers 80,242 acres and is governed by the terms of an Exploration and
Exploitation Contract with ANH, which was signed June 27, 2005. We are the
operator and hold a 100% participation interest. The discovery of the Costayaco
field in the Chaza block was the result of drilling the Costayaco-1 exploration
well in the second quarter of 2007. This well commenced production in July
2007.
This
block is in a combined fourth and fifth exploration period which carries the
obligation to drill two exploration wells and expires December 26, 2010. We
drilled the first exploration well at the end of 2009, the Dantayaco-1 well,
which was plugged and abandoned in January 2010, and the second exploration well
is scheduled to be drilled in 2010. There is one further exploration period
after December 26, 2010: period six lasts six months and 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
phase. Within 60 days following the date of the return of the property, we must
carry out an abandonment program to the satisfaction of ANH. In conjunction with
the abandonment, we must establish and maintain an abandonment fund to ensure
that financial resources are available at the end of the contract.
Work
completed in 2009 included drilling development wells Costayaco 7 through 10.
Costayaco 8 through 10 are producing wells and Costayaco-7 was suspended. We
also completed work on pipeline and storage facilities, to keep pace with
expanding production, and completed the development well Costayaco-6 as an
injector well.
24
In 2010,
we plan to acquire 70 square kilometers of 3D seismic, drill one
exploration well and one Costayaco injector well. We plan further upgrades to
the storage and transportation systems, camp, office and warehouse. We are
undertaking a project to electrify the field, which will reduce our dependence
on diesel fuel for power and lead to cost savings.
Azar
We
acquired an 80% interest in the Azar property through a farm-in agreement
entered into 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%. We are now in
the fourth exploration period which carries a commitment to drill one well.
There are two more exploration periods that follow, each lasting 12 months and
including an obligation to drill one exploration well. The exploration phase of
the contract expires in 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 acquired 50 square kilometers of 3D seismic and 40 kilometers of 2D
seismic.
In 2010,
we plan to drill two exploration wells (one of which we will pay 10% of the
costs, and one of which we will pay 40% of the costs), and acquire 75 square
kilometers of 3D seismic.
Piedemonte
Norte
In June
2009, we completed the conversion of our Technical Evaluation Areas in the
Putumayo Basin to blocks with ANH Exploration and Exploitation Contracts.
Piedemonte Norte covers 78,742 acres and is held 100% by Gran Tierra and was
part of the Putumayo West A Technical Evaluation Area. From June to December
2009 we were in a pre-exploration phase in which we performed environmental
evaluation and survey work. We are now in the first exploration period of a
total of six periods. The exploration phase of the contract expires in December
2015, and the exploitation phase would expire 24 years after commerciality of a
discovery is approved. The first exploration period contains a commitment to
acquire, process and interpret 70 kilometers of 2D seismic by December 16, 2010.
We plan to exceed this commitment in 2010 with a program to acquire 70 square
kilometers of 2D seismic and to drill one exploration well.
Piedemonte
Sur
Piedemonte
Sur was also part of the Putumayo West A Technical Evaluation Area and became an
exploration block with an ANH Exploration and Exploitation Contract in June
2009. Piedemonte Sur covers 73,898 acres and is held 100% by Gran Tierra. From
June to December 2009, we were in a pre-exploration phase in which we performed
environmental evaluation and survey work. We are now in the first exploration
period of a total of six periods in the contract. The exploration phase ends in
December 2015, and the exploitation phase would expire 24 years after
commerciality of a discovery is approved. The first exploration period contains
a commitment to drill one exploration well to a minimum depth of 3,000 feet, by
December 16, 2010. Our work plans for 2010 are to acquire 10 kilometers of
2D seismic and drill one exploration well.
Rumiyaco
Rumiyaco
was part of the Putumayo West B Technical Evaluation Area and became an
exploration block with an ANH Exploration and Exploitation Contract in June
2009. Rumiyaco covers 82,624 acres and is held 100% by Gran Tierra. From June to
December 2009, we were in a pre-exploration phase in which we performed
environmental evaluation and survey work. We are now in the first exploration
period of a total of six periods in the contract. The exploration phase ends in
December 2015, and the exploitation phase would expire 24 years after
commerciality of a discovery is approved. The first exploration period contains
a commitment to reprocess 60 kilometers of 2D seismic and acquire, process and
interpret 68 kilometers of 2D seismic by December 16, 2010. Our work plans for
2010 are to acquire 95 square kilometers of 3D seismic, 12 kilometers of 2D
seismic and drill one exploration well.
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.
25
In 2010
we have nominal capital spending for facility upgrades planned.
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
kilometers 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 five of the exploration contract, which expires October 24,
2010. There are a total of 6 exploration periods, each lasting 12 months and
requiring one exploration well.
In 2009,
we swapped 79 square kilometers of 3D seismic acquisition in exchange for the
original contract’s obligation of one exploration well for the current period.
Acquisition of this seismic was completed in 2009.
We have
signed a letter of intent with a third party regarding the sale of our entire
interest in the Garibay block. We are currently finalizing the assignment
agreement. Once the agreement is complete and signed, we will have to obtain ANH
approval to finalize the sale. We have not budgeted any activity for this block
in 2010.
Rio
Magdalena
The Rio
Magdalena Association Contract with Ecopetrol was signed in February 2002. The
Rio Magdalena block covers 72,312 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. 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.
This
block is in the sixth exploration period, which expires September 14, 2010 and
carries the obligation to finish the long term production test of the Popa-2
well drilled in 2008, and acquire 80 kilometers of 2D seismic. In 2009, we
acquired 75 square kilometers of 3D seismic, completed the Popa 2 well, and
began the long term production test of this well. Later in 2009, we entered into
an assignment agreement, under which we sold this block to Alange Corporation of
Colombia. We are awaiting ANH and Ecopetrol approval to finalize the
sale.
Mecaya
The
Mecaya Exploration and Exploitation contract was signed June 2006. The Mecaya
contract area covers 74,128 acres in southern Colombia in the Putumayo Basin. We
are the operator and currently have a 15% participation interest and two
partners have 55% and 30% each. 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 were contractually obligated to complete this work
by June 2009, however the contract terms have been suspended due to operational
difficulties in the area. There are two more exploration periods following, each
of which are 12 months in duration. The third period has an obligation to
acquire seismic data, and the fourth period has the obligation to drill one
exploration well. The exploitation phase for this contract expires 24 years
after commerciality is approved for any discovery. The property will be returned
to the government upon expiration of the production contract.
In 2009,
we entered into an assignment agreement, under which we sold this block to
Alange Corporation of Colombia. We are awaiting ANH and Ecopetrol approval to
finalize the sale.
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
June 5, 2010, and has an obligation to re-enter an existing well and drill two
exploration wells. All remaining periods are 12 months in length and carry a
work obligation of one well. The exploitation phase would last 24 years from any
declaration of a commercial discovery.
In 2009,
due to operating conditions in the area, we were not able to complete any
exploration work. We have signed a letter of intent with a third party regarding
the sale of our entire interest in the Catguas block. We are currently
finalizing the assignment agreement. Once the agreement is complete and signed,
we will have to obtain ANH approval to finalize the sale. We have not budgeted
any activity for this block in 2010.
26
Guachiría
Norte, Guachiria and Guachiria Sur Blocks
In 2009,
we completed several work items that were part of the commitments in the
contracts for these blocks. On the Guachiria Sur block, we completed the
acquisition of 115 kilometers of 3D seismic. On the Guachiria block, we removed
all production equipment. On the Guachiria Norte block, we drilled one
exploration well, Puinaves-2, which was plugged and abandoned.
In April
2009, we sold our entire interest in these three blocks to Lewis Energy
Colombia. Principal terms included consideration of $7 million, plus settlement
of outstanding issues between Lewis Energy and Gran Tierra Energy's subsidiary,
Solana Resources, comprising an initial cash payment of $4 million at closing,
followed by 15 monthly installments of $200,000 beginning June 1, 2009 and
extending through August 3, 2010.
We retained a 10% overriding royalty interest on the Guachiria Sur block
in the event of a discovery, designed to reimburse 200% of Gran Tierra’s net
costs for previously acquired seismic data. We assumed responsibility for
environmental liabilities existing on the properties at the date of sale,
estimated at approximately $1.2 million.
Talora
In 2009,
the Montmelo-1 exploration well was drilled on the Talora block. This well was
paid for 100% by Petrosouth Energy Corporation, and they had 100% working
interest in that well.
Effective
October 23, 2009, we assigned our 100% interest in the Talora block to
Petrosouth Energy Corporation Sucursal Colombia for no proceeds. The assignment
has been approved by ANH.
San
Pablo Block
In 2009,
we acquired 50 kilometers of 3D seismic, as part of our commitment under the
exploration contract. We relinquished our license rights to this block later in
the year.
Oil
and Gas Properties - Argentina
In
September 2005, we entered Argentina through the acquisition of a 14% interest
in the Palmar Largo joint venture, and a 50% interest in each of the Nacatimbay
and Ipaguazu blocks. In 2006, we purchased additional properties in Argentina,
including the remaining 50% interest in Nacatimbay and Ipaguazu, a 50% interest
in El Vinalar and 100% interests in El Chivil, Valle Morado, Surubi and Santa
Victoria. In 2009 we relinquished our rights to the Nacatimbay block. 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 2010 involves optimization of well performance and operating
expenses to maximize net revenues from the property.
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
2009, we installed production facilities and commenced production from the
Ipaguazu-1 well. In 2010, we will maintain and upgrade the production facilities
for this well.
El
Vinalar
We
acquired a 50% working interest in the El Vinalar Block in June 2006. This
acquisition added a significant new land position and a small amount of
production. El Vinalar covers 59,080 acres and contains a portfolio of
exploration leads and oil field enhancement opportunities.
27
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.
One
successful workover was completed in 2009, along with facilities maintenance and
improvements to production equipment.
In 2010,
we plan to continue regular field maintenance and workover 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
with two remaining in production. The contract for this field expires in 2015
with the option for a ten year extension.
In 2009,
we performed one successful workover, converted one well to a water disposal
well and upgraded facilities.
In 2010,
we plan to continue facilities maintenance activities.
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 it is paying its share of well costs from its share of production
from Proa-1.
In 2009,
we performed a successful workover on the Proa-1 well. In 2010, we plan to
conduct facilities maintenance activities.
Valle
Morado
We
purchased the Valle Morado block at the end of 2006. It covers 49,915 acres, and
we are the operator and have a 93.2% working interest. The remaining 6.8%
interest is held equally by two other companies. The previous owners have the
option to back-in for 18% working interest under certain
circumstances.
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 conducted a feasibility study of production with promising results. We
signed a sales agreement with Albenesi SA for sale of test production. In 2010,
we plan to do a workover and sidetrack of the well, with the goal of making it
ready for production.
Santa
Victoria
We
purchased the Santa Victoria block late in 2006. Santa Victoria covers 1,033,642
acres and we are the operator with a 100% working interest. It is an exploration
block with no production history. In 2010 we plan to acquire 150 square
kilometers of 3D seismic and 200 kilometers of 2D seismic.
Nacatimbay
We
relinquished this block in 2009 and have no further commitments.
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 is assessed a royalty of 5%, for production between 5,000 and 100,000
barrels of oil per day there is a linear sliding scale between 5% and 20%.
Production over 100,000 barrels per day has a royalty of 20%. 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 $3.5 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 2009, we completed EIA’s and the community consultation process. Also
in 2009, we conducted engineering feasibility and geological studies and
evaluated the results of the aeromagnetic-gravity studies, and opened offices in
Lima and Iquitos. In 2010, we plan to acquire 277 kilometers of 2D seismic
on each block, as well as drill
two wells on each block, on locations identified from our aeromagnetic-gravity
data.
28
Reserves
No
estimates of reserves comparable to those included herein have been included in
a report to any federal agency other than the SEC.
The
process of estimating oil and gas reserves is complex and requires significant
judgment, as discussed in Item 1A. “Risk Factors”. As a result we have developed
internal policies for estimating and evaluating reserves, and 100% of our
reserves are audited by an independent reservoir engineering firm, GLJ
Associates Ltd., at least annually. The reserve estimation process will require
us to use significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each property.
Therefore the accuracy of the reserve estimate is dependent on the quality of
the data, the accuracy of the assumptions based on the data, and the
interpretations and judgment related to the data.
The
policies we have developed are applied company wide, and are comprehensive in
nature. The result of the policies is SEC compliant reserve estimates and
disclosures. The policy is applied by all staff involved in generating and
reporting reserve estimates including geological, engineering and finance
personnel. Calculations and data are reviewed at multiple levels of the
organization to ensure consistent and appropriate standards and
procedures.
The
primary internal technical person in charge of overseeing the preparation of our
reserve estimates is the Manager of Reservoir Engineering. He has a bachelor’s
degree of science in petroleum engineering and is a professional engineer and
member of the Association of Professional Engineers, Geologists and
Geophysicists of Alberta. He is currently responsible for our engineering
activities including reserves reporting, asset evaluation, field development and
monitoring production operations. He has over 29 years of industry experience in
various domestic and international engineering and management
roles.
The
technical person responsible for overseeing the reserves audit is the Manager,
Engineering at GLJ Associated Ltd. He has bachelor’s degree of science in
engineering physics and is a registered professional engineer in the province of
Alberta . He is currently responsible for reserve reporting. He
has over 20 years of industry experience in various domestic and international
engineering and management roles.
The SEC
definitions related to oil and natural gas reserves, per Regulation S-X,
reflecting our use of deterministic reserve estimation methods, are as
follows:
|
|
·
|
Reserves.
Reserves
are estimated remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date, by
application of development projects to known accumulations. In addition,
there must exist, or there must be a reasonable expectation that there
will exist, the legal right to produce or a revenue interest in the
production, installed means of delivering oil and gas or related
substances to market, and all permits and financing required to implement
the project.
|
29
|
|
·
|
Proved oil and gas reserves.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date
forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations—prior to the time at which
contracts providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract
the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable
time.
|
|
|
(i)
|
The
area of the reservoir considered as proved
includes:
|
|
|
A.
|
The
area identified by drilling and limited by fluid contacts, if any,
and
|
|
|
B.
|
Adjacent
undrilled portions of the reservoir that can, with reasonable certainty,
be judged to be continuous with it and to contain economically producible
oil or gas on the basis of available geoscience and engineering
data.
|
|
(ii)
|
In
the absence of data on fluid contacts, proved quantities in a reservoir
are limited by the lowest known hydrocarbons (LKH) as seen in a well
penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable
certainty.
|
|
(iii)
|
Where
direct observation from well penetrations has defined a highest known oil
(HKO) elevation and the potential exists for an associated gas cap, proved
oil reserves may be assigned in the structurally higher portions of the
reservoir only if geoscience, engineering, or performance data and
reliable technology establish the higher contact with reasonable
certainty.
|
|
(iv)
|
Reserves
which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are
included in the proved classification
when:
|
|
|
A.
|
Successful
testing by a pilot project in an area of the reservoir with properties no
more favorable than in the reservoir as a whole, the operation of an
installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of
the engineering analysis on which the project or program was based;
and.
|
|
|
B.
|
The
project has been approved for development by all necessary parties and
entities, including governmental
entities.
|
|
(v)
|
Existing
economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The price shall be the
average price during the 12-month period prior to the ending date of the
period covered by the report, determined as an unweighted arithmetic
average of the first-day-of-the-month price for each month within such
period, unless prices are defined by contractual arrangements, excluding
escalations based upon future
conditions.
|
|
|
·
|
Probable reserves.
Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be
recovered.
|
|
|
(i)
|
When
deterministic methods are used, it is as likely as not that actual
remaining quantities recovered will exceed the sum of estimated proved
plus probable reserves. When probabilistic methods are used, there should
be at least a 50% probability that the actual quantities recovered will
equal or exceed the proved plus probable reserves
estimates.
|
|
(ii)
|
Probable
reserves may be assigned to areas of a reservoir adjacent to proved
reserves where data control or interpretations of available data are less
certain, even if the interpreted reservoir continuity of structure or
productivity does not meet the reasonable certainty criterion. Probable
reserves may be assigned to areas that are structurally higher than the
proved area if these areas are in communication with the proved
reservoir.
|
|
(iii)
|
Probable
reserves estimates also include potential incremental quantities
associated with a greater percentage recovery of the hydrocarbons in place
than assumed for proved reserves.
|
|
(iv)
|
See
also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of section
210.4-10(a) of Regulations S-X..
|
30
|
|
·
|
Possible reserves.
Possible reserves are those additional reserves that are less
certain to be recovered than probable
reserves.
|
|
|
(i)
|
When
deterministic methods are used, the total quantities ultimately recovered
from a project have a low probability of exceeding proved plus probable
plus possible reserves. When probabilistic methods are used, there should
be at least a 10% probability that the total quantities ultimately
recovered will equal or exceed the proved plus probable plus possible
reserves estimates.
|
|
(ii)
|
Possible
reserves may be assigned to areas of a reservoir adjacent to probable
reserves where data control and interpretations of available data are
progressively less certain. Frequently, this will be in areas where
geoscience and engineering data are unable to define clearly the area and
vertical limits of commercial production from the reservoir by a defined
project.
|
|
(iii)
|
Possible
reserves also include incremental quantities associated with a greater
percentage recovery of the hydrocarbons in place than the recovery
quantities assumed for probable
reserves.
|
|
(iv)
|
The
proved plus probable and proved plus probable plus possible reserves
estimates must be based on reasonable alternative technical and commercial
interpretations within the reservoir or subject project that are clearly
documented, including comparisons to results in successful similar
projects.
|
|
(v)
|
Possible
reserves may be assigned where geoscience and engineering data identify
directly adjacent portions of a reservoir within the same accumulation
that may be separated from proved areas by faults with displacement less
than formation thickness or other geological discontinuities and that have
not been penetrated by a wellbore, and the registrant believes that such
adjacent portions are in communication with the known (proved) reservoir.
Possible reserves may be assigned to areas that are structurally higher or
lower than the proved area if these areas are in communication with the
proved reservoir.
|
|
(vi)
|
Pursuant
to paragraph (a)(22)(iii) of section 210.4-10(a) of Regulations S-X, where
direct observation has defined a highest known oil (HKO) elevation and the
potential exists for an associated gas cap, proved oil reserves should be
assigned in the structurally higher portions of the reservoir above the
HKO only if the higher contact can be established with reasonable
certainty through reliable technology. Portions of the reservoir that do
not meet this reasonable certainty criterion may be assigned as probable
and possible oil or gas based on reservoir fluid properties and pressure
gradient interpretations.
|
|
|
·
|
Reasonable
Certainty.
If deterministic methods are used, reasonable
certainty means a high degree of confidence that the quantities will be
recovered. A high degree of confidence exists if the quantity
is much more likely to be achieved than not, and as changes due to
increased availability of geoscience (geological, geophysical and
geochemical), engineering and economic data are made to estimated ultimate
recovery (EUR) with time, reasonably certain EUR is much more likely to
increase or remain constant that to
decrease.
|
|
|
·
|
Deterministic estimate.
The method of estimating reserves or resources is called
deterministic when a single value for each parameter (from the geoscience,
engineering, or economic data) in the reserves calculation is used in the
reserves estimation procedure.
|
|
|
·
|
Developed oil and gas
reserves.
Developed oil and gas reserves are reserves of any
category that can be expected to be
recovered:
|
|
|
(i)
|
Through
existing wells with existing equipment and operating methods or in which
the cost of the required equipment is relatively minor compared to the
cost of a new well; and
|
|
(ii)
|
Through
installed extraction equipment and infrastructure operational at the time
of the reserves estimate if the extraction is by means not involving a
well.
|
31
|
|
·
|
Undeveloped oil and gas
reserves.
Undeveloped oil and gas reserves are reserves of any
category that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
|
|
|
(i)
|
Reserves
on undrilled acreage shall be limited to those directly offsetting
development spacing areas that are reasonably certain of production when
drilled, unless evidence using reliable technology exists that establishes
reasonable certainty of economic producibility at greater
distances.
|
|
(ii)
|
Undrilled
locations can be classified as having undeveloped reserves only if a
development plan has been adopted indicating that they are scheduled to be
drilled within five years, unless the specific circumstances, justify a
longer time.
|
|
(iii)
|
Under
no circumstances shall estimates for undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have
been proved effective by actual projects in the same reservoir or an
analogous reservoir, as defined in paragraph (a)(2) of section 201.4-10(a)
of Regulation S-X, or by other evidence using reliable technology
establishing reasonable certainty.
|
The following table sets forth our oil
reserves net of all royalties and third party interests as of December 31, 2009
(all quantities in thousands of barrels of oil)
.
Probable reserves are those additional
reserves that are less certain to be recovered than proved reserves but which,
together with proved reserves, are as likely as not to be recovered.
When deterministic methods are
used, as they are in our case, it is as likely as not that actual remaining
quantities recovered will exceed the sum of estimated proved plus probable
reserves. Possible reserves are those additional reserves that are less certain
to be recovered than probable reserves. When deterministic methods are used, the
total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves.
|
Reserves
|
||||||||
|
Reserves Category
|
Liquids*
(thousands of
barrels) |
Natural Gas
(millions of cubic
feet) |
||||||
|
PROVED
|
||||||||
|
Developed:
|
||||||||
|
Colombia
|
20,194 | 1,113 | ||||||
|
Argentina
|
1,080 | 756 | ||||||
|
Undeveloped
|
||||||||
|
Colombia
|
597 | - | ||||||
|
Argentina
|
211 | - | ||||||
|
TOTAL
PROVED
|
22,082 | 1,869 | ||||||
|
PROBABLE
|
||||||||
|
Developed
|
||||||||
|
Colombia
|
4,002 | 652 | ||||||
|
Argentina
|
829 | 1,087 | ||||||
|
Undeveloped
|
- | |||||||
|
Colombia
|
969 | - | ||||||
|
Argentina
|
20 | - | ||||||
|
TOTAL
PROBABLE
|
5,820 | 1,739 | ||||||
|
POSSIBLE
|
||||||||
|
Developed
|
||||||||
|
Colombia
|
6,088 | 1,388 | ||||||
|
Argentina
|
682 | 4,266 | ||||||
|
Undeveloped
|
||||||||
|
Colombia
|
3,341 | - | ||||||
|
Argentina
|
1,427 | 28,866 | ||||||
|
TOTAL
POSSIBLE
|
11,538 | 34,520 | ||||||
*Liquids
include oil and Natural Gas Liquids. We have Natural Gas Liquids
reserves in small amounts in Argentina only. Colombia Liquids
reserves are 100% oil.
32
Proved
Undeveloped Reserves
In
Colombia, our proved undeveloped reserves decreased from 8.7 million barrels at
December 31, 2008 to 0.6 million barrels at December 31, 2009. All of
these proved undeveloped reserves are located in our Costayaco
field. The decrease is due to a movement from proved undeveloped
reserves to proved developed reserves through the drilling of four development
wells in 2009 (Costayaco 7 through 10), at a capital cost of approximately $30
million. The reserves remaining in the proved undeveloped category for Colombia
are planned for development in 2011. Our proved undeveloped reserves
in Argentina increased slightly from 187,000 barrels at December 31, 2008 to
211,000 barrels at December 31, 2009 due to a revision to forecast development
activity. We expect to develop these reserves within the next three
to four years.
Sensitivity
of Reserves to Prices by Principal Product Type and Price Scenario
|
Proved Reserves
|
Probable Reserves
|
Possible Reserves
|
||||||||||||||||||||||
|
Price Case
|
Liquids
(thousands of
barrels)
|
Natural Gas
(thousands of
cubic feet)
|
Liquids
(thousands of
barrels)
|
Natural Gas
(thousands of
cubic feet)
|
Liquids
(thousands of
barrels)
|
Natural Gas
(thousands of
cubic feet)
|
||||||||||||||||||
|
WTI +10%
|
||||||||||||||||||||||||
|
Colombia
|
20,567 | 1,113 | 4,778 | 652 | 9,263 | 1,388 | ||||||||||||||||||
|
Argentina
|
1,291 | 756 | 831 | 1,087 | 2,048 | 33,132 | ||||||||||||||||||
|
Total
|
21,858 | 1,869 | 5,609 | 1,739 | 11,311 | 34,520 | ||||||||||||||||||
|
WTI – 10%
|
||||||||||||||||||||||||
|
Colombia
|
21,039 | 1,113 | 5,200 | 652 | 9,595 | 1,388 | ||||||||||||||||||
|
Argentina
|
1,291 | 756 | 831 | 1,087 | 2,048 | 33,132 | ||||||||||||||||||
|
Total
|
22,330 | 1,869 | 6,031 | 1,739 | 11,643 | 34,520 | ||||||||||||||||||
The price
cases presented involve changes to the WTI price – one with a 10% increase, the
second with a 10% decrease. Natural gas prices are not affected by WTI,
therefore the volumes of natural gas reserves do not change. Additionally, the
oil price in Argentina is set by the government as described in Item “1
Business” under the caption “Markets and Customers”. The price in Argentina is
not sensitive to changes in the WTI price, therefore the price scenarios
considered do not result in changes to oil and natural gas reserves for
Argentina. Cost schedules were held constant for the two price
cases.
Production
Revenue and Price History
Certain
information concerning oil and natural gas production, prices, revenues (net of
all royalties) and operating expenses for the three years ended December 31,
2009 is set forth in Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” and in the Unaudited Supplementary Data
provided following our Financial Statements in Item 8. We prepared the estimate
of standardized measure of proved reserves in accordance with the Financial
Accounting Standards Board (“FASB”) ASC 932, “Extractive Activities – Oil and
Gas”.
Drilling
Activities
The
following table summarizes the results of our development and exploration
drilling activity for the past three years. Wells labeled as “In Progress”, were
in progress as of December 31, 2009.
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Colombia
|
||||||||||||||||||||||||
|
Exploration
|
||||||||||||||||||||||||
|
Productive
|
-
|
-
|
1.00
|
0.40
|
2.00
|
0.85
|
||||||||||||||||||
|
Dry
|
2.00
|
0.70
|
1.00
|
0.70
|
4.00
|
1.50
|
||||||||||||||||||
|
In
Progress
|
1.00
|
1.00
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Development
|
||||||||||||||||||||||||
|
Productive
|
3.00
|
3.00
|
3.00
|
1.50
|
1.00
|
0.50
|
||||||||||||||||||
|
Dry
|
1.00
|
1.00
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
In
Progress
|
1.00
|
0.70
|
1.00
|
1.00
|
-
|
-
|
||||||||||||||||||
|
Total
Colombia
|
8.00
|
6.40
|
6.00
|
3.60
|
7.00
|
2.85
|
||||||||||||||||||
|
Argentina
|
||||||||||||||||||||||||
|
Exploration
|
||||||||||||||||||||||||
|
Productive
|
-
|
-
|
1.00
|
0.85
|
-
|
-
|
||||||||||||||||||
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
In
Progress
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Development
|
||||||||||||||||||||||||
|
Productive
|
-
|
-
|
-
|
-
|
1.00
|
0.50
|
||||||||||||||||||
|
Dry
|
-
|
-
|
-
|
-
|
||||||||||||||||||||
|
In
Progress
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Total
Argentina
|
-
|
-
|
1.00
|
0.85
|
1.00
|
0.50
|
||||||||||||||||||
|
Peru
|
||||||||||||||||||||||||
|
Exploration
|
||||||||||||||||||||||||
|
Productive
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
In
Progress
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Development
|
||||||||||||||||||||||||
|
Productive
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
In
Progress
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Total
Peru
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Total
|
8.00
|
6.40
|
7.00
|
4.45
|
8.00
|
3.35
|
||||||||||||||||||
33
Following
are the results as of February 15, 2010 of wells in progress at December 31,
2009:
|
Productive
|
Dry
|
Still in Progress
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Colombia
|
-
|
-
|
1.00
|
1.00
|
1.00
|
0.70
|
||||||||||||||||||
|
Argentina
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Peru
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Total
|
-
|
-
|
1.00
|
1.00
|
1.00
|
0.70
|
||||||||||||||||||
Well
Statistics
The
following table sets forth our producing wells as of December 31,
2009.
|
Oil Wells
|
Gas Wells
|
Total Wells
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Colombia
|
26.00
|
15.35
|
-
|
-
|
26.00
|
15.35
|
||||||||||||||||||
|
Argentina
|
22.00
|
7.45
|
-
|
-
|
22.00
|
7.45
|
||||||||||||||||||
|
Peru
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Total
|
48.00
|
22.80
|
-
|
-
|
48.00
|
22.80
|
||||||||||||||||||
Developed
and Undeveloped Acreage
The
following table sets forth our developed and undeveloped oil and gas lease and
mineral acreage as of December 31, 2009.
|
Developed
|
Undeveloped
|
Total
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Colombia
|
230,310
|
163,062
|
826,493
|
590,314
|
1,056,803
|
753,376
|
||||||||||||||||||
|
Argentina
|
594,584
|
256,755
|
1,033,889
|
1,033,889
|
1,628,473
|
1,290,644
|
||||||||||||||||||
|
Peru
|
-
|
-
|
3,436,040
|
3,436,040
|
3,436,040
|
3,436,040
|
||||||||||||||||||
|
Total
|
824,894
|
419,817
|
5,296,422
|
5,060,243
|
6,121,316
|
5,480,060
|
||||||||||||||||||
Our net
developed acreage in Colombia includes acreage in the Santana block (less than
1%); the Guayuyaco block (4.9%); the Chaza block (10.7%); and the Magangue block
(1.0%). Our net undeveloped arcreage in Colombia is in the Azar block
(2.7%); the Piedemonte Norte block (10.5%); the Rumiyaco block (11.0%); the
Mecaya block (1.5%); the Rio Magdalena block (3.8%); the Catguas block (39%);
and the Garibay block (5.0%).
In
Argentina, our net developed acreage includes acreage in the Palmar Largo block
(3.7%); the Ipaguazu block (1.7%); the El Vinalar block (2.4%); the El Chivil
block (2.4%); and the Valle Morado block (3.8%); the undeveloped
acreage is in the Santa Victoria block (80.1%).
34
Ecopetrol
and Gran Tierra Colombia, the contracting parties of the Guayuyaco Association
Contract, are engaged in a dispute regarding the interpretation of the procedure
for allocation of oil produced and sold during the long term test of the
Guayuyaco-1 and Guayuyaco-2 wells. There is a material difference in the
interpretation of the procedure established in Clause 3.5 of Attachment-B of the
Guayuyaco Association Contract. Ecopetrol interprets the contract to provide
that the extended test production up to a value equal to 30% of the direct
exploration costs of the wells is for Ecopetrol’s account only and serves as
reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra
Colombia’s contention is that this amount is merely the recovery of 30% of the
direct exploration costs of the wells and not exclusively for benefit of
Ecopetrol. There has been no agreement between the parties, and Ecopetrol
has filed a lawsuit in the Contravention Administrative Court in the District
of Cauca regarding this matter. Gran Tierra Colombia filed a response on
April 29, 2008 in which it refuted all of Ecopetrol’s claims and requested a
change of venue to the courts in Bogota. Closing arguments were presented
by all parties during 2009. We are awaiting the courts
decision. At this time no amount has been accrued in the financial
statements as Gran Tierra does not consider it probable that a loss will be
incurred. Ecopetrol is claiming damages of approximately $5.1
million.
We have
several other lawsuits and claims pending for which we currently cannot
determine the ultimate result. We record costs as they are incurred or become
determinable. We believe the resolution of these matters would not have a
material adverse effect on our consolidated financial position or results of
operations.
Executive
Officers of the Registrant
Set
forth below is information regarding our executive officers as of February 25,
2010.
|
Name
|
Age
|
Position
|
||
|
Dana
Coffield
|
51
|
President
and Chief Executive Officer; Director
|
||
|
Martin
H. Eden
|
62
|
Chief
Financial Officer
|
||
|
Shane
O’Leary
|
53
|
Chief
Operating Officer
|
||
|
Rafael
Orunesu
|
54
|
President
and General Manager Gran Tierra Energy Argentina
|
||
|
Julian
Garcia
|
51
|
President
and General Manager Gran Tierra Energy Colombia
|
||
|
Julio
Cesar Moreira
|
48
|
President
and General Manager Gran Tierra Energy
Brasil
|
Dana Coffield, President, Chief
Executive Officer and Director.
Before joining Gran Tierra as President,
Chief Executive Officer and a Director in May, 2005, Mr. Coffield led the
Middle East Business Unit for EnCana Corporation, 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 the Chief Financial Officer of Chariot Energy Inc., a
Canadian private oil and gas company. From January 2004 to
September 2004, he was the Chief Financial Officer of Assure Energy Inc., a
publicly traded oil and gas company listed in the United States. From
January 2001 to December 2002, he was Chief Financial Officer of
Geodyne Energy Inc., a publicly listed Canadian oil and gas company. From 1997
to 2000, he was Controller and subsequently Chief Financial Officer of Kyrgoil
Corporation, a publicly listed Canadian oil and gas company with operations in
Central Asia. He spent nine years with Nexen Inc. (1986-1996), including three
years as Finance Manager for Nexen’s Yemen operations and six years in Nexen’s
financial reporting and special projects areas in its Canadian head office.
Mr. Eden has worked in public practice, including two years as an audit
manager for Coopers & Lybrand in East Africa. He is currently a director of
Touchstone Oil and Gas Ltd., a private company. Mr. Eden holds a
Bachelor of Science degree in Economics from Birmingham University, England, a
Masters of Business Administration from Henley Management College/Brunel
University, England, and is a member of the Institute of Chartered Accountants
of Alberta and the Institute of Chartered Accountants in England and
Wales.
35
Shane P. O’Leary, Chief Operating
Officer.
Mr. O’Leary joined the company as Chief Operating
Officer effective March 2, 2009. Mr. O’Leary’s regional experience includes
South America, North Africa, the Middle East, the former Soviet Union, and North
America.
Prior to
joining Gran Tierra 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. He brings a mix of operations management, project
evaluation, production geology, reservoir and production engineering skills to
Gran Tierra, with a South American focus. He was most recently Engineering
Manager for Pluspetrol Peru, from 1997 through 2004, responsible for planning
and development operations in the Peruvian North jungle. He participated in
numerous evaluation and asset purchase and sale transactions covering Latin
America and North Africa, incorporating 200,000,000 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.
Julian Garcia, President and General
Manager Gran Tierra Energy Colombia.
Mr. Garcia joined our company
as President and General Manager Gran Tierra Energy Colombia in December
2009. Mr. Garcia has more than 25 years of petroleum industry
experience in Colombia and internationally. He has extensive experience in all
aspects of the petroleum industry, including exploration and production
operations, commercial, finance, project management and strategic
leadership. He has held a range of progressively senior positions,
technical and financial, at companies including Ecopetrol, BP, and the National
Hydrocarbon Agency, where he was Technical Director. Most recently, Julian was
General Manager for Emerald Energy Plc Colombia, where the company grew reserves
10-fold in less than five years. Mr. Garcia holds a Bachelors of Civil
Engineering and a Masters in Economics from Universidad de Los Andes, a Masters
in Civil Engineering from Colorado State University USA, and a Masters of
Business Administration from the University of Birmingham UK.
Julio Moreira, President Gran Tierra
Energy Brasil.
Mr. Moreira joined our company as President, Gran
Tierra Brazil in September 2009. Mr. Moreira has over 25 years of
experience working for international companies in Brazil in senior business
development positions. Most recently, he was Managing Director for IBV Petroleo
Ltda from September 2008 to August 2009, and Brazil Country Manager for EnCana
Corporation from December 2001 to September 2008, where he was instrumental in
capturing assets which were later sold for a combined value of over $500
million. Mr. Moreira holds an Information Technology degree from Universidade
Federal Fluminense in Rio de Janeiro, and a graduate degree in Marketing from
Rio Catholic University. In addition, he has attended Executive Management
programs in Oil and Gas at Thunderbird (USA) and the Ivey Business School at the
University of Western Ontario (Canada).
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 Amex
(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 22, 2010 there were approximately: 66 holders of record of
shares of our common stock and 227,414,754 shares outstanding with $0.001 par
value; and one share of Special A Voting Stock, $0.001 par value representing
approximately 13 holders of record of 8,642,857 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 7
holders of record of 12,581,523 shares of Gran Tierra Exchangeco Inc., which are
exchangeable on a 1-for-1 basis into shares of our common stock.
36
On
February 22, 2010, the last reported sales price of our shares on the NYSE Amex
was $5.47. For the periods indicated from January 1, 2008 to April 8, 2008, the
following table sets forth the high and low closing 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 2009, the following table shows the high and
low closing sale prices per share of our common stock as reported on the NYSE
Amex (formerly American Stock Exchange).
|
High
|
Low
|
|||||||
|
Fourth
Quarter 2009
|
$
|
6.00
|
$
|
3.99
|
||||
|
Third
Quarter 2009
|
$
|
4.26
|
$
|
2.92
|
||||
|
Second
Quarter 2009
|
$
|
3.51
|
$
|
2.31
|
||||
|
First
Quarter 2009
|
$
|
3.50
|
$
|
2.06
|
||||
|
Fourth
Quarter 2008
|
$
|
3.69
|
$
|
1.89
|
||||
|
Third
Quarter 2008
|
$
|
7.93
|
$
|
3.17
|
||||
|
Second
Quarter 2008
|
$
|
8.25
|
$
|
3.36
|
||||
|
First
Quarter 2008
|
$
|
4.22
|
$
|
2.50
|
||||
Dividend
Policy
We have
never declared or paid dividends on the shares of common stock and we intend to
retain future earnings, if any, to support the development of the business and
therefore do not anticipate paying cash dividends for the foreseeable future.
Payment of future dividends, if any, will be at the discretion of our board of
directors after taking into account various factors, including current financial
condition, operating results and current and anticipated cash needs. Under the
terms of our credit facility we cannot pay any dividends if we are in default
under the facility, and if we are not in default then are required to obtain
bank approval for any dividend payments made by us exceeding $2 million in
any fiscal year.
Unregistered
Sales of Equity Securities
On
fourteen separate dates beginning on October 1, 2009 and ending on December 31,
2009, we sold an aggregate of 871,977 shares of our common stock for an
aggregate purchase price of $956,321.05. These shares were issued to four
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.
37
Performance
Graph
| 11/05 | 12/05 | 12/06 | 12/07 | 12/08 | 12/09 | |||||||||||||||||||
|
Gran
Tierra Energy Inc
|
100.00 | 184.00 | 79.33 | 174.67 | 186.67 | 382.00 | ||||||||||||||||||
|
Russell
Small Cap Completeness
|
100.00 | 105.03 | 120.66 | 126.52 | 77.20 | 106.29 | ||||||||||||||||||
|
Dow
Jones US Exploration & Production TSM
|
100.00 | 104.56 | 109.88 | 154.15 | 90.91 | 128.65 |
The Dow Jones US Exploration and
Production TSM was previously named the DJ Wilshire Exploration and
Production.
38
(Thousands
of U.S. Dollars, Except Share and Per Share Amounts)
|
Year Ended
December 31,
|
Year Ended
December 31,
|
Year Ended
December 31,
|
Year Ended
December 31,
|
Period Ended
December 31,
|
||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005 (1)
|
||||||||||||||||
|
Statement
of Operations Data
|
||||||||||||||||||||
|
Revenues
and other income
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 262,629 | $ | 112,805 | $ | 31,853 | $ | 11,721 | $ | 1,059 | ||||||||||
|
Interest
|
1,087 | 1,224 | 425 | 352 | - | |||||||||||||||
|
Total
revenues and other income
|
263,716 | 114,029 | 32,278 | 12,073 | 1,059 | |||||||||||||||
|
Expenses
|
||||||||||||||||||||
|
Operating
|
40,784 | 19,218 | 10,474 | 4,233 | 395 | |||||||||||||||
|
Depletion,
depreciation and accretion
|
135,863 | 25,737 | 9,415 | 4,088 | 462 | |||||||||||||||
|
General
and administrative
|
28,787 | 18,593 | 10,232 | 6,999 | 2,482 | |||||||||||||||
|
Liquidated
damages
|
- | - | 7,367 | 1,528 | - | |||||||||||||||
|
Derivative
financial instruments (gain) loss
|
190 | (193 | ) | 3,040 | - | - | ||||||||||||||
|
Foreign
exchange (gain) loss
|
19,797 | 6,235 | (78 | ) | 371 | (31 | ) | |||||||||||||
|
Total
expenses
|
225,421 | 69,590 | 40,450 | 17,219 | 3,308 | |||||||||||||||
|
Income
(loss) before income taxes
|
38,295 | 44,439 | (8,172 | ) | (5,146 | ) | (2,249 | ) | ||||||||||||
|
Income
tax (expense) recovery
|
(24,354 | ) | (20,944 | ) | (295 | ) | (678 | ) | 29 | |||||||||||
|
Net
income (loss)
|
$ | 13,941 | $ | 23,495 | $ | (8,467 | ) | $ | (5,824 | ) | $ | (2,220 | ) | |||||||
|
Net
income (loss) per common share — basic
|
$ | 0.06 | $ | 0.19 | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.16 | ) | |||||||
|
Net
income (loss) per common share — diluted
|
$ | 0.05 | $ | 0.16 | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.16 | ) | |||||||
|
As at
December
31,
|
As at
December
31,
|
As at
December
31,
|
As at
December
31,
|
As at
December
31,
|
||||||||||||||||
|
Balance Sheet Data
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
|
Cash
and cash equivalents
|
$ | 270,786 | $ | 176,754 | $ | 18,189 | $ | 24,101 | $ | 2,221 | ||||||||||
|
Working
capital (including cash)
|
215,161 | 132,807 | 8,058 | 14,541 | 2,765 | |||||||||||||||
|
Oil
and gas properties
|
709,568 | 765,050 | 63,202 | 56,093 | 7,887 | |||||||||||||||
|
Deferred
tax asset - long term
|
7,218 | 10,131 | 1,839 | 444 | 29 | |||||||||||||||
|
Total
assets
|
1,143,808 | 1,072,625 | 112,797 | 105,537 | 12,371 | |||||||||||||||
|
Deferred
tax liability and deferred remittance tax - long term
|
217,528 | 214,210 | 10,567 | 9,876 | - | |||||||||||||||
|
Other
long-term liabilities
|
4,258 | 4,251 | 1,986 | 634 | 68 | |||||||||||||||
|
Shareholders’
equity
|
$ | 816,426 | $ | 791,926 | $ | 76,792 | $ | 76,195 | $ | 11,039 | ||||||||||
(1) 2005
Selected Financial Data is for the period from incorporation on January 26, 2005
to December 31, 2005.
39
We made our initial acquisition of oil
and gas producing and non-producing properties in Argentina in
September 2005 for a total purchase price of approximately $7 million.
Prior to that time we had no revenues. In June 2006, we acquired
Argosy’s assets in
Colombia
for consideration
of $37.5 million cash, 870,647 shares of our common stock and overriding and net
profit interests in certain assets valued at $1 million. In
November 2008, we acquired Solana for $67
1.8
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
.
This report, and in particular this
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E
of the Securities Exchange Act of 1934. Please see the cautionary language at
the very beginning of Part I of this Annual Report on Form 10-K regarding the
identification and risks relating to forward-looking statements, as well as Part
I, Item 1A “Risk Factors” in this Annual Report on Form 10-K.
The
following discussion of our financial condition and results of operations should
be read in conjunction with the Financial Statements and Supplementary Data as
set out in Part II – Item 8 of this Annual Report on Form 10-K.
Overview
We are an
independent international energy company incorporated in the United States and
engaged in oil and natural gas acquisition, exploration, development and
production. We are headquartered in Calgary, Alberta, Canada and operate in
South America in Colombia, Argentina and Peru, and have a business development
office in Brazil.
In
September 2005, we acquired our initial oil and gas interests and
properties, which were in Argentina. During 2006, we increased our oil and gas
interests and property base through further acquisitions in Colombia, Argentina
and Peru. We funded acquisitions of our properties in Colombia and Argentina
through a series of private placements of our securities that occurred between
September 2005 and 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”), an international resource company engaged in the acquisition,
exploration, development and production of oil and natural gas in Colombia and
incorporated in Alberta, Canada. At the date of acquisition, Solana held various
working interests in nine blocks in Colombia including a 50% working interest in
the Chaza Block, which includes the Costayaco field, and a 35% working interest
in the Guayuyaco Block, which includes the Juanambu field.
During
the third quarter of 2009, we opened a business development office in Rio de
Janeiro, Brazil.
The oil
and gas industry has been adversely impacted by the downturn in the global
economy and the decline in average crude oil prices during 2009 as compared to
2008. Although our revenue has been negatively affected by these lower oil
prices, our increase in production has more than offset 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
and cash on hand, 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 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, Peru and Brazil; 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 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.
40
Financial
and Operational Highlights (1)
|
Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
||||||||||||||||
|
Estimated
Proved Oil and Gas Reserves, net of royalties - Millions of Barrels of Oil
Equivalent
|
22.4 | 15 | 19.4 | 203 | 6.4 | |||||||||||||||
|
Production
- Barrels of Oil Equivalent per Day
|
12,684 | 248 | 3,635 | 143 | 1,495 | |||||||||||||||
|
Prices
Realized - Per Barrel of Oil Equivalent
|
$ | 56.73 | (33 | ) | $ | 84.78 | 45 | $ | 58.39 | |||||||||||
|
Revenue
and Other Income ($000's)
|
$ | 263,716 | 131 | $ | 114,029 | 253 | $ | 32,278 | ||||||||||||
|
Net
Income (Loss) ($000's)
|
$ | 13,941 | (41 | ) | $ | 23,495 | 377 | $ | (8,467 | ) | ||||||||||
|
Net
Income (Loss) Per Share - Basic
|
$ | 0.06 | (68 | ) | $ | 0.19 | 311 | $ | (0.09 | ) | ||||||||||
|
Net
Income (Loss) Per Share - Diluted
|
$ | 0.05 | (69 | ) | $ | 0.16 | 278 | $ | (0.09 | ) | ||||||||||
|
Capital
Expenditures ($000's)
|
$ | 88,124 | 89 | $ | 46,728 | 181 | $ | 16,625 | ||||||||||||
|
As at December 31,
|
||||||||||||||||||||
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
||||||||||||||||
|
Cash
& Cash Equivalents ($000's)
|
$ | 270,786 | 53 | $ | 176,754 | 872 | $ | 18,189 | ||||||||||||
|
Working
Capital (including cash & cash equivalents) ($000's)
|
$ | 215,161 | 62 | $ | 132,807 | 1,548 | $ | 8,058 | ||||||||||||
|
Property,
Plant & Equipment ($000's)
|
$ | 712,743 | (7 | ) | $ | 767,552 | 1,101 | $ | 63,918 | |||||||||||
(1) The
Financial and Operating Highlights include the operations of Solana subsequent
to our acquisition of Solana on November 14, 2008.
Financial Highlights for
Year Ended December 31, 2009
|
·
|
In
2009, production of crude oil (net after royalty and inventory
adjustments) averaged 12,684 barrels of oil per day (“BOPD”), an increase
of 248% over 2008, due mainly to production from the new development wells
in the Costayaco field in the Chaza Block in Colombia where Gran Tierra
has a 100% working interest subsequent to the acquisition of Solana.
During the year, our production was disrupted for 56 days from damage to
the Trans Andean Pipeline and a general strike at the beginning of
January.
|
|
·
|
Revenue
and other income increased by 131% from 2008 due to increased production
partially offset by lower oil
prices.
|
|
·
|
A
foreign exchange loss of $19.8 million, of which $19.5 million is an
unrealized non-cash foreign exchange loss, was recorded in 2009 primarily
due to the translation of a deferred tax liability recorded on the
purchase of Solana. The deferred tax liability is denominated in Colombian
pesos and the devaluation of 9% in the U.S. dollar against the Colombian
Peso in 2009 resulted in the foreign exchange
loss.
|
|
·
|
Oil
and gas property expenditures for 2009 include further development
drilling in the Costayaco field, including Costayaco – 6, Costayaco – 7,
Costayaco – 8, Costayaco – 9 and Costayaco – 10, facility construction in
Costayaco, the drilling of the Puinaves – 2 exploration well in the
Guachiria Norte Block, the drilling of the Dantayaco – 1 exploration well
in the Chaza Block, and acquisition of 2D or 3D seismic in the Guachiria,
Garibay, Rio Magdelena, Chaza, and San Pablo blocks, all in
Colombia.
|
41
|
·
|
Our
cash position of $270.8 million (excluding restricted cash) at December
31, 2009 increased from $176.8 million at December 31, 2008 as a result of
increased cash provided by operating activities, partially offset by
capital expenditures.
|
|
·
|
Working
capital (including cash & cash equivalents) was $215.2 million at
December 31, 2009, which is an $82.4 million increase from December 31,
2008, due mainly to increased cash as at December 31, 2009 compared
to December 31, 2008.
|
|
·
|
Property,
plant & equipment as at December 31, 2009 was $712.7 million, a
decrease from December 31, 2008, primarily as a result of increased
depletion, depreciation and accretion (“DD&A”), partially offset by
capital additions. DD&A for 2009 included a $1.9 million ceiling test
impairment loss in our Argentina cost
center.
|
Operational Highlights for
the Year Ended December 31, 2009
|
·
|
Costayaco
Field
Oil Production Milestones
At
the end of August 2009, we reached our daily gross production plateau
target for the Costayaco field in Colombia. In addition, production from
the Costayaco field reached five million cumulative barrels of gross oil
production on September 10, 2009 triggering additional government
royalties.
|
|
·
|
Successful
Production Testing of Costayaco
–
8, Costayaco – 9
and
Costayaco – 10
In
June 2009, we completed logging operations and initiated production
testing of Costayaco – 8. Testing of Costayaco – 8 was completed in early
July and the well came on production later in the month. In September
2009, we completed logging operations and production testing of Costayaco
– 9. Testing of Costayaco – 9 was completed in early September and the
well was tied in and put on production later in the month. In December
2009, we completed logging operations and production testing of Costayaco
– 10; the well was tied in and put on production at the beginning of
January 2010. Costayaco – 6 and – 7 were tested and
suspended.
|
|
·
|
Successful
Production Testing of Valle Morado Well
in
Argentina
In
November 2009, we commenced an extended production test on the VM.x-1001
discovery well in the Valle Morado Field in Argentina. The well was tested
at approximately 7 million standard cubic feet per day (“MMSCF/day”) of
natural gas with approximately 3,500 barrels of water per day; the
estimated wellhead flowing pressure was 2,550 pounds per square inch
(“psi”). We have a gas sales contract to sell up to 6 MMSCF/day of gas at
$2.90 per million British Thermal Units (“MMbtu”) until the commencement
of a planned workover for the well in July
2010.
|
|
·
|
New Exploration and Exploitation Contracts in
Colombia
In
June 2009, we signed three Exploration and Exploitation contracts with the
National Hydrocarbon Agency totaling 235,264 acres in which we have a 100%
working interest. The Piedemonte Norte Block lies southwest of the Chaza
Block where the Costayaco field is located. The Piedemonte Sur Block is
located immediately west of the Orito Field, the largest oil field in the
Putumayo Basin. Further south, the Rumiyaco Block is located in
the central Putumayo Basin.
|
|
·
|
Property Divestment
In
April 2009, we closed the sale of our interests in the Guachiria Norte,
Guachiria, and Guachiria Sur blocks in Colombia for net proceeds of $6.3
million.
|
|
·
|
Environmental Impact Assessments Submitted to
Peruvian Government
The
seismic and stratigraphic drilling environmental impact
assessments were submitted to the Peruvian Government in April 2009
for Block 128, and in June 2009 for Block 122. Consultations with
communities in the region have
concluded.
|
42
Consolidated
Results of
Operations
|
Year Ended December 31,
|
||||||||||||||||||||
|
Consolidated Results of Operations (1)
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
|||||||||||||||
|
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 262,629 | 133 | $ | 112,805 | 254 | $ | 31,853 | ||||||||||||
|
Interest
|
1,087 | (11 | ) | 1,224 | 188 | 425 | ||||||||||||||
| 263,716 | 131 | 114,029 | 253 | 32,278 | ||||||||||||||||
|
Operating
expenses
|
40,784 | 112 | 19,218 | 83 | 10,474 | |||||||||||||||
|
Depletion,
depreciation and accretion
|
135,863 | 428 | 25,737 | 173 | 9,415 | |||||||||||||||
|
General
and administrative expenses
|
28,787 | 55 | 18,593 | 82 | 10,232 | |||||||||||||||
|
Foreign
exchange (gain) loss
|
19,797 | 218 | 6,235 | (8,094 | ) | (78 | ) | |||||||||||||
|
Other
|
190 | 198 | (193 | ) | (102 | ) | 10,407 | |||||||||||||
| 225,421 | 224 | 69,590 | 72 | 40,450 | ||||||||||||||||
|
Income
(loss) before income taxes
|
38,295 | (14 | ) | 44,439 | (644 | ) | (8,172 | ) | ||||||||||||
|
Income
tax expense
|
(24,354 | ) | 16 | (20,944 | ) | 7,000 | (295 | ) | ||||||||||||
|
Net
income (loss)
|
$ | 13,941 | (41 | ) | $ | 23,495 | (377 | ) | $ | (8,467 | ) | |||||||||
|
Production, Net of
Royalties
|
||||||||||||||||||||
|
Oil
and NGL's ("bbl") (2)
|
4,621,546 | 248 | 1,328,145 | 145 | 541,069 | |||||||||||||||
|
Natural
gas ("mcf") (2)
|
49,028 | 237 | 14,559 | (45 | ) | 26,631 | ||||||||||||||
|
Total
production ("boe") (2) (3)
|
4,629,717 | 248 | 1,330,572 | 144 | 545,508 | |||||||||||||||
|
Average Prices
|
||||||||||||||||||||
|
Oil
and NGL's ("per bbl")
|
$ | 56.79 | (33 | ) | $ | 84.89 | 44 | $ | 58.79 | |||||||||||
|
Natural
gas ("per mcf")
|
$ | 3.93 | (20 | ) | $ | 4.93 | 192 | $ | 1.69 | |||||||||||
|
Consolidated Results of Operations ("per
boe")
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 56.73 | (33 | ) | $ | 84.78 | 45 | $ | 58.39 | |||||||||||
|
Interest
|
0.23 | (75 | ) | 0.92 | 18 | 0.78 | ||||||||||||||
| 56.96 | (34 | ) | 85.70 | 45 | 59.17 | |||||||||||||||
|
Operating
expenses
|
8.81 | (39 | ) | 14.44 | (25 | ) | 19.20 | |||||||||||||
|
Depletion,
depreciation and accretion
|
29.35 | 52 | 19.34 | 12 | 17.26 | |||||||||||||||
|
General
and administrative expenses
|
6.22 | (55 | ) | 13.97 | (26 | ) | 18.76 | |||||||||||||
|
Foreign
exchange (gain) loss
|
4.28 | (9 | ) | 4.69 | 3,450 | (0.14 | ) | |||||||||||||
|
Other
|
0.04 | 127 | (0.15 | ) | (101 | ) | 19.08 | |||||||||||||
| 48.70 | (7 | ) | 52.29 | (29 | ) | 74.16 | ||||||||||||||
|
Income
(loss) before income taxes
|
8.26 | (75 | ) | 33.41 | (323 | ) | (14.99 | ) | ||||||||||||
|
Income
tax expenses
|
(5.26 | ) | (67 | ) | (15.74 | ) | 2,815 | (0.54 | ) | |||||||||||
|
Net
income (loss)
|
$ | 3.00 | (83 | ) | $ | 17.67 | 214 | $ | (15.53 | ) | ||||||||||
(1)
Consolidated results of operations include the operations of Solana subsequent
to our acquisition of Solana on November 14, 2008.
(2) Gas
volumes are converted to barrel of oil equivalent (“boe”) at the rate of six
thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate
relative energy content of gas and oil, which rate is not necessarily indicative
of the relationship of oil and gas prices. Gran Tierra changed from the
conversion of gas volumes to boe at a rate of 20 mcf of gas per barrel of oil to
provide volume information consistent with standard industry practice and to
reflect natural gas’s relative energy content to a barrel of oil. As a result,
the 2008 and 2007 boe volumes presented have increased by 1,699 boe and 3,107
boe, respectively, from those volumes previously disclosed. Natural gas liquids
(“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,
2009 Compared to the Results for
the
Year
Ended
December 31,
2008
As a
result of the Solana acquisition, we increased our working interest to 100% in
the Costayaco field and 70% in the Juanambu field, in Colombia, which resulted
in increased production, revenue, operating costs, and DD&A in
2009.
43
Net
income of $13.9 million, or $0.06 per share basic and $0.05 per share diluted,
was recorded in 2009 compared to $23.5 million, or $0.19 per share basic and
$0.16 per share diluted, in 2008. A foreign exchange loss of $19.8 million,
of which $19.5 million is an unrealized non-cash foreign exchange loss, an
increase of $110.1 million in DD&A to $135.9 million, higher operating and
general and administrative expenses, and increased income tax expense, more than
offset the higher oil revenues in 2009.
R
evenue
and
interest
increased 131% to $263.7 million in 2009 compared to $114.0
million in 2008. This was due to an increase of 248% in crude oil production
partially offset by a 33% decrease in crude oil prices.
Crude oil and NGL
production
, net after royalties, in 2009 increased to 4.6 million barrels
compared to 1.3 million barrels in 2008, due mainly to increased production from
our Colombia operations. Average realized crude oil prices for 2009 decreased to
$56.79 per barrel from $84.89 per barrel in 2008, reflecting lower West Texas
Intermediate (“WTI”) oil prices.
Operating
expenses
for 2009 amounted to $40.8 million, a 112% increase from the
prior year. The increase in operating expenses is due to expanded operations and
increased production levels in Colombia. However, operating expenses on a boe
basis in 2009 were $8.81 per boe, a 39% decline from 2008 reflecting a
reduction in fixed costs per barrel due to production increases at
Costayaco.
DD&A
expense
for 2009 increased to $135.9 million compared to $25.7 million in 2008.
Increased production levels, as well as amortization expense of $102.5
million in 2009 ($6.9 million in 2008) related to the fair value of property,
plant and equipment recorded on the acquisition of Solana, accounted for the
increases. On a boe basis, DD&A in 2009 was $29.35 compared to $19.34
for 2008. This 52% increase was primarily due to the significant additions to
the proved depletable cost base resulting from the Solana acquisition partially
offset by higher proved reserves in Colombia. DD&A for 2009 included a $1.9
million ceiling test impairment loss in our Argentina cost center. This
impairment loss resulted from higher estimated future operating costs to produce
remaining reserves.
General and
administrative (“G&A”)
expenses
of $28.8 million for 2009 was 55% higher than 2008 due to increased employee
related costs reflecting the expanded operations in Colombia. However, due to
higher production in 2009, G&A expenses per boe decreased 55% to $6.22 per
boe compared to $13.97 per boe for 2008.
The
foreign exchange
loss
of $19.8 million for 2009, of which $19.5 million is an unrealized
non-cash foreign exchange loss, compares to $6.2 million recorded in 2008. These
losses primarily represent foreign exchange losses resulting 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, foreign exchange gains and losses have
been calculated on conversion to the U.S. dollar functional
currency.
Income tax
expense
for 2009 amounted to $24.4 million compared to $20.9 million
recorded in 2008. This represents an increase of 16% in annual income tax
expense, primarily due to an increase in foreign currency translation losses
that are neither taxable nor deductible for tax purposes in each of the
respective jurisdictions. The increase in the 2009 effective tax rate to 64%
from 47% in 2008 is primarily due to the increase in the valuation allowance
associated with increased losses in our U.S., Canadian and Peru business units.
The variance from the 35% U.S. statutory rate for 2009 results from an increase
in the valuation allowances as described above, and the recapture of
enhanced tax depreciation incentive in Colombia, due to a disposal of assets
during the year, offset by enhanced tax depreciation taken on oil and gas
capital expenditures. The variance from the 35% U.S. statutory rate for 2008 is
primarily attributable to recognition of previously unrecognized foreign tax
credits, foreign currency translation fluctuations that are not taxable or
deductible in the related foreign jurisdictions, and valuation allowances taken
on losses incurred in the U.S., Canada, and Peru.
Consolidated
Results
of Operations
for the
Year
Ended
December 31,
200
8
Compared to the Results for the
Year
Ended
December 31,
200
7
In 2008,
a 145% increase in crude oil production and a 45% 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.
Cr
ude 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 high 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 $14.44 per boe, a 25% decline from 2007.
44
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
DD&A
to $25.7 million. A 12% increase in the average depletion rate to $19.34 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.
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.
The
foreign exchange
loss
of $6.2 million for 2008 compares to a $78,000 foreign exchange gain
recorded in 2007. The losses in 2008 primarily represent foreign exchange losses
resulting 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, foreign exchange
gains and losses have been calculated on conversion to the U.S. dollar
functional currency.
Other expenses
in 2008 represent a derivative financial instruments gain of $0.2 million
from the costless collar financial derivative contract for crude oil prices
entered into pursuant to the terms and conditions of Gran Tierra’s credit
facility. 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.
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. We used additional Colombian tax deductions
associated with capital investment in producing oil and natural gas
properties to 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.
Estimated
Oil and Gas Reserves
Estimated
proved oil reserves, net of royalties, as of December 31, 2009, were 22.1
million barrels, a 15% increase from the estimated proved reserves as at
December 31, 2008. The increase resulted from our successful development
drilling program in Colombia which led to conversion of probable reserves to
proved and which more than offset 2009 production of oil. Estimated probable and
possible oil reserves, net of royalties, as of December 31, 2009, were 5.8
million barrels and 11.5 million barrels, respectively.
Estimated
proved gas reserves, net of royalties, as of December 31, 2009, were
1.9 billion cubic feet (“bcf”), a 61% increase from the estimated proved
reserves as at December 31, 2008. The increase resulted from our successful
testing of the VM.x-1001 discovery well in the Valle Morado Field in Argentina.
Estimated probable and possible gas reserves, net of royalties, as of December
31, 2009, were 1.7 bcf and 34.5 bcf, respectively.
The
estimated proved reserves as at December 31, 2008 of 19.4 million barrels,
increased by 203% compared with 2007 year-end reserve levels. The increase
resulted from our successful development drilling program in Colombia which led
to the 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 5.3 million barrels of oil to our reserve
base and the acquisition of Solana contributed approximately 9.0 million
barrels.
Segmented
Results of Operations
Our
operations are carried out in Colombia, Argentina, Peru, and Brazil, 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 and Brazil. In 2009, Colombia generated 94.5% of our
revenue and other income and reflects the operations of Solana subsequent to the
acquisition of Solana on November 14, 2008.
45
Segmented
Results – Colombia
|
Year Ended December 31,
|
||||||||||||||||||||
|
Segmented Results of Operations – Colombia (1)
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
|||||||||||||||
|
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 248,834 | 141 | $ | 103,202 | 335 | $ | 23,749 | ||||||||||||
|
Interest
|
466 | (53 | ) | 995 | 348 | 222 | ||||||||||||||
| 249,300 | 139 | 104,197 | 335 | 23,971 | ||||||||||||||||
|
Operating
expenses
|
33,091 | 173 | 12,117 | 196 | 4,097 | |||||||||||||||
|
Depletion,
depreciation and accretion
|
127,213 | 473 | 22,199 | 224 | 6,850 | |||||||||||||||
|
General
and administrative expenses
|
13,011 | 173 | 4,769 | 181 | 1,696 | |||||||||||||||
|
Foreign
exchange (gain) loss
|
20,158 | 204 | 6,622 | 4,345 | (156 | ) | ||||||||||||||
| 193,473 | 323 | 45,707 | 266 | 12,487 | ||||||||||||||||
|
Segment
income before income taxes
|
$ | 55,827 | (5 | ) | $ | 58,490 | 409 | $ | 11,484 | |||||||||||
|
Production, Net of
Royalties
|
||||||||||||||||||||
|
Oil
and NGL's ("bbl") (2)
|
4,284,230 | 295 | 1,085,198 | 226 | 333,157 | |||||||||||||||
|
Natural
gas ("mcf") (2)
|
49,028 | 237 | 14,559 | - | - | |||||||||||||||
|
Total
production ("boe") (2) (3)
|
4,292,401 | 295 | 1,087,625 | 226 | 333,157 | |||||||||||||||
|
Average Prices
|
||||||||||||||||||||
|
Oil
and NGL's ("per bbl")
|
$ | 58.04 | (39 | ) | $ | 95.04 | 33 | $ | 71.28 | |||||||||||
|
Natural
gas ("per mcf")
|
$ | 3.93 | (20 | ) | $ | 4.93 | - | $ | - | |||||||||||
|
Segmented Results of Operations ("per
boe")
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 57.97 | (39 | ) | $ | 94.89 | 33 | $ | 71.28 | |||||||||||
|
Interest
|
0.11 | (88 | ) | 0.91 | 36 | 0.67 | ||||||||||||||
| 58.08 | (39 | ) | 95.80 | 33 | 71.95 | |||||||||||||||
|
Operating
expenses
|
7.71 | (31 | ) | 11.14 | (9 | ) | 12.30 | |||||||||||||
|
Depletion,
depreciation and accretion
|
29.64 | 45 | 20.41 | (1 | ) | 20.56 | ||||||||||||||
|
General
and administrative expenses
|
3.03 | (31 | ) | 4.38 | (14 | ) | 5.09 | |||||||||||||
|
Foreign
exchange (gain) loss
|
4.70 | (23 | ) | 6.09 | 1,396 | (0.47 | ) | |||||||||||||
| 45.08 | 7 | 42.02 | 12 | 37.48 | ||||||||||||||||
|
Segment
income before income taxes
|
$ | 13.00 | (76 | ) | $ | 53.78 | 56 | $ | 34.47 | |||||||||||
|
|
(1)
|
Segmented
results of operations for Colombia include the operations of Solana
subsequent to our acquisition of Solana on November 14,
2008.
|
|
|
(2)
|
Gas
volumes are converted to barrel of oil equivalent (“boe”) at the rate of
six mcf of gas per barrel of oil, based upon the approximate relative
energy content of gas and oil, which rate is not necessarily indicative of
the relationship of oil and gas prices. Gran Tierra changed from the
conversion of gas volumes to boe at a rate of 20 mcf of gas per barrel of
oil to provide volume information consistent with standard industry
practice and to reflect natural gas’s relative energy content to a barrel
of oil. As a result, the 2008 boe volumes presented have increased by
1,699 boe from those volumes previously disclosed. Natural gas liquids
(“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, 2009 Compared
to the Results for the Year Ended December 31, 2008
For the
year ended December 31, 2009,
income before
income taxes
from Colombia amounted to $55.8 million compared to
income before taxes of $58.5 million recorded in 2008. An increase in
production revenue was more than offset by increased expenses including a
$13.5 million increase in foreign exchange loss to $20.2 million, of which $19.3
million is an unrealized non-cash foreign exchange loss, primarily due to the
translation of deferred taxes. Also, a $105.0 million increase in DD&A,
primarily a result of the amortization of the fair value of Solana’s property,
plant and equipment recorded upon our acquisition of Solana, partially offset
the increase in production revenue. Higher operating expenses due to increased
Colombian production and increased general and administrative expenses from
expanded activities also contributed to a reduction in income before income
taxes.
For the
year ended December 31, 2009,
production of
crude oil and NGLs
, net after royalties, increased by 295% to 4.3 million
barrels compared to 1.1 million barrels in 2008. The incremental production
volumes from Solana properties for the year ended December 31, 2009 were 2.2
million barrels of oil, compared to 69,747 barrels of oil in 2008. These
production levels are after government royalties ranging from 8% to 22.5% and
third party royalties of 2% to 10%.
46
Gran
Tierra’s Colombian operating results for the year ended December 31, 2009 are
principally impacted by the inclusion of production from three new development
wells in the Costayaco field, including Solana’s 50% share of production from
Costayaco, and Solana’s 35% share of production from Juanambu – 1 in the
Guayuyaco Block. In 2008, Colombia production included production from Costayaco
– 1, 2, 3, 4, 5, and Juanambu – 1 along with production from the Santana
Block.
Our
production in 2009 and 2008 was impacted by political and economic factors in
Colombia. In the second and third quarter of 2009, and the first and second
quarter of 2008, sections of the Ecopetrol operated Trans Andean Pipeline were
damaged, which temporarily reduced our deliveries to Ecopetrol. 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. 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.
As a
result of these factors, deliveries to Ecopetrol in 2009 were reduced to
approximately 3,800 BOPD, net after royalties, for 32 days between July and
August 2009, and reduced to approximately 2,200 BOPD, net after royalties, for
14 days in June, and we were shut in for the first 10 days of January. During
the first quarter of 2008, deliveries to Ecopetrol were reduced to approximately
1,900 BOPD, net after royalties, for 18 days and in the second quarter of 2008
deliveries were reduced to approximately 2,300 BOPD, net after royalties, for 14
days.
Revenue and
interest
were negatively impacted by a decline in net realized crude oil
prices in 2009 compared to 2008. The average net realized prices for crude oil,
which are based on WTI prices, decreased by 39% to $58.04 per barrel for the
year ended December 31, 2009 compared to 2008. However, substantially increased
production resulted in our revenue and interest from Colombia for the year ended
December 31, 2009 increasing by 139% to $249.3 million from 2008.
As a
result of achieving gross field production of five million barrels in our
Costayaco field during the month of September 2009, Gran Tierra is now subject
to an additional government royalty payable. This royalty is calculated on 30%
of the field production revenue over an inflation adjusted trigger point. That
trigger point for Gran Tierra was $30.22 for 2009. Production revenue for this
calculation is based on production volumes net of other government royalty
volumes. Average government royalties at Costayaco with gross production of
19,000 BOPD and $70 WTI per barrel are approximately 24.8%, including the
additional government royalty of approximately 17.0%. The National
Hydrocarbons Agency sliding scale royalty at 19,000 BOPD is approximately 9.4%
and this royalty is deductible prior to calculating the additional government
royalty.
O
perating
expenses
for the year ended December 31, 2009 increased to $33.1
million from $12.1 million in 2008. The increased operating expenses resulted
from the increase in production and the inclusion of the Solana operations
acquired on November 14, 2008. However, on a per boe basis, operating
expenses for 2009 declined to $7.71 compared to $11.14 incurred in 2008,
reflecting the reduction of fixed operating costs per barrel as total production
increased.
For
2009,
DD&A
expense increased to $127.2 million from $22.2 million in
2008. Increased production levels coupled with a higher depletable cost base
resulting from the Solana acquisition, partially offset by higher crude oil
reserve levels, accounted for the increase in DD&A expense. The
incremental DD&A expense recorded as a result of the Solana acquisition was
$102.5 million for the year ended December 31, 2009 compared to $6.9 million
recorded in 2008. On a per boe basis, the DD&A expense in Colombia increased
by 45% to $29.64 for 2009, compared with $20.41 for 2008, due to the higher
depletable cost base reflecting the Solana properties recorded at fair value
upon acquisition, partially offset by increased proved reserves.
Higher
G&A
expenses incurred to manage the increased level of development and operating
activities, the Solana acquired properties, and increased stock-based
compensation expense resulted in
G&A
expense increasing to $13.0 million for the year ended December 31, 2009 from
$4.8 million incurred in 2008. On a per boe basis, G&A expense in 2009
decreased by 31% to $3.03 from $4.38 in 2008, due to higher
production.
The
foreign exchange
loss
of
$20.2 million for the year ended December 31, 2009 includes an unrealized
non-cash foreign exchange loss of $19.3 million which resulted primarily 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, foreign
exchange gains and losses have been calculated on conversion to the U.S. dollar
functional currency. A strengthening in the Colombian peso against the U.S.
dollar results in foreign exchange losses, estimated at $99,000 for each one
peso decrease in the exchange rate of the Colombian peso to one US
dollar.
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 2008 was $53.78 versus $34.47 recorded in the prior
year.
47
In 2008,
P
roduction 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
damaged, which temporarily reduced our deliveries to Ecopetrol. Ecopetrol was
able to restore deliveries within one to two weeks of these
incidents.
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 volume from Solana properties for the period from the
acquisition date of November 14, 2008 to December 31, 2008 was 69,747 barrels of
oil and 14,559 mcf of natural gas, and was severely impacted by the general
strike affecting the 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.
O
perating
expenses
increased to $12.1 million in 2008 from $4.1 million in 2007.
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 $11.14 in 2008 compared to $12.30
per barrel incurred in 2007.
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 the
Solana 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 were 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 2008 was $20.41,
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 boe basis, the G&A expense decreased by 14% to $4.38 for
2008.
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
foreign operations and as a result, a foreign exchange loss has been calculated
on conversion to the U.S. dollar functional currency.
Capital
Program - Colombia
Gran
Tierra’s focus for 2009 was to continue with the development of 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 $81.4 million for the year ended December 31, 2009.
48
|
Segmented Capital Expenditures – Colombia
|
Year Ended December 31,
|
||||
|
Block and Activity
|
2009
|
||||
|
(Millions of U.S. Dollars)
|
|||||
|
Chaza
|
Drilled
and tested Costayaco -6, -7, -8, -9, commenced drilling of Costayaco -10,
drilled Dantayaco-1, commenced 2D seismic program, installed
facilities and equipment
|
$ | 53.6 | ||
|
Rio
Magdalena
|
Completion
and long term testing of Popa-2 well and 3D 75 kilometers (“km”) seismic
program
|
3.4 | |||
|
Guachiria
|
Completed
acquisition of 115 square kilometers (“km
2
”)
of 3D seismic
|
1.0 | |||
|
Guachiria
Norte
|
Drilling
of the Puinaves -2 exploration well, which was dry
|
5.8 | |||
|
Guachiria
Sur
|
Completed
acquisition of 115 km
2
of
3D seismic
|
3.7 | |||
|
Garibay
|
Completed
acquisition of 110 km
2
of
3D seismic
|
3.4 | |||
|
Azar
|
Commencement
of 2D and 3D seismic programs
|
2.3 | |||
|
Guayayaco
|
Juanambu
production separator
|
2.0 | |||
|
Leasehold
improvements
|
1.8 | ||||
|
Capitalized
G&A and other
|
4.4 | ||||
|
Segmented
Capital Expenditures – Colombia
|
$ | 81.4 | |||
For
comparison, for the year ended December 31, 2008, we spent $31.7 million on
capital projects. Included in this amount was $6.8 million in capital
expenditures related to the Solana properties subsequent to the
acquisition.
|
Segmented Capital Expenditures - Colombia
|
Year Ended December 31,
|
||||
|
Block and Activity
|
2008
|
||||
|
(Millions of U.S. Dollars)
|
|||||
|
Chaza
|
Drilled
and tested Costayaco -2, -3, -4, -5, commenced drilling of Costayaco -6,
and facilities and equipment
|
$ | 17.8 | ||
|
Costayaco
pipeline
|
15
km 8-inch pipeline to connect Costayaco field to existing pipeline
infrastructure
|
4.0 | |||
|
Azar
|
Acquired
40 km
2
of
3D seismic and we performed one well re-entry on the Palmera 1 well,
encountering oil
|
1.3 | |||
|
Guachiria
|
Drilling
Los Aceites-1 and Primavera-1
|
1.1 | |||
|
Guachiria
Norte
|
Drilled
an exploration well, Zafiro-1, in November 2008, which was
dry
|
3.4 | |||
|
Capitalized
G&A and other
|
4.1 | ||||
|
Segmented
Capital Expenditures – Colombia
|
$ | 31.7 | |||
Due to
the high cost to transport oil produced from the Guachiria Blocks in the Llanos
Basin, acquired from Solana in Colombia, production was shut in February
2009. In April 2009, Gran Tierra signed an asset purchase and sale agreement
with a third party for Gran Tierra's interests in the Guachiria Norte,
Guachiria, and Guachiria Sur blocks. Principal terms included consideration
of $7.0 million between the third party and Gran Tierra's subsidiary,
Solana, comprising an initial cash payment of $4.0 million at closing, followed
by 15 monthly installments of $200,000 each beginning June 1, 2009 and extending
through August 3, 2010, less settlement of outstanding amounts. The sale closed
on April 16, 2009 and
Gran Tierra recorded net
proceeds of $6.3 million. Gran Tierra retained a 10% overriding royalty interest
on the Guachiria Sur block, which, in the event of a discovery, is designed to
reimburse 200% of our costs for previously acquired seismic data.
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 other 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.
49
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 and acquired the Putumayo A and B technical evaluation
areas.
Segmented
Results – Argentina
|
Year Ended December 31,
|
||||||||||||||||||||
|
Segmented Results of Operations - Argentina
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
|||||||||||||||
|
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 13,795 | 44 | $ | 9,603 | 18 | $ | 8,104 | ||||||||||||
|
Interest
|
127 | 452 | 23 | 53 | 15 | |||||||||||||||
| 13,922 | 45 | 9,626 | 19 | 8,119 | ||||||||||||||||
|
Operating
expenses
|
7,537 | 7 | 7,027 | 11 | 6,327 | |||||||||||||||
|
Depletion,
depreciation and accretion
|
8,339 | 146 | 3,390 | 37 | 2,477 | |||||||||||||||
|
General
and administrative expenses
|
2,318 | 13 | 2,055 | 21 | 1,705 | |||||||||||||||
|
Foreign
exchange (gain) loss
|
(42 | ) | (114 | ) | 311 | 266 | 85 | |||||||||||||
| 18,152 | 42 | 12,783 | 21 | 10,594 | ||||||||||||||||
|
Segment
loss before income taxes
|
$ | (4,230 | ) | 34 | $ | (3,157 | ) | 28 | $ | (2,475 | ) | |||||||||
|
Production, Net of
Royalties
|
||||||||||||||||||||
|
Oil
and NGL's ("bbl") (1)
|
337,316 | 39 | 242,947 | 17 | 207,912 | |||||||||||||||
|
Natural
gas ("mcf") (2)
|
- | - | - | (100 | ) | 26,631 | ||||||||||||||
|
Total
production ("boe") (2) (3)
|
337,316 | 39 | 242,947 | 14 | 212,351 | |||||||||||||||
|
Average Prices
|
||||||||||||||||||||
|
Oil
and NGL's ("per bbl")
|
$ | 40.90 | 3 | $ | 39.53 | 2 | $ | 38.76 | ||||||||||||
|
Natural
gas ("per mcf")
|
$ | - | - | $ | - | (100 | ) | $ | 1.69 | |||||||||||
|
Segmented Results of Operations ("per
boe")
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 40.90 | 3 | $ | 39.53 | 4 | $ | 38.16 | ||||||||||||
|
Interest
|
0.38 | 322 | 0.09 | 29 | 0.07 | |||||||||||||||
| 41.28 | 4 | 39.62 | 4 | 38.23 | ||||||||||||||||
|
Operating
expenses
|
22.34 | (23 | ) | 28.92 | (3 | ) | 29.80 | |||||||||||||
|
Depletion,
depreciation and accretion
|
24.72 | 77 | 13.95 | 20 | 11.66 | |||||||||||||||
|
General
and administrative expenses
|
6.87 | (19 | ) | 8.46 | 5 | 8.03 | ||||||||||||||
|
Foreign
exchange (gain) loss
|
(0.12 | ) | (109 | ) | 1.28 | 220 | 0.40 | |||||||||||||
| 53.81 | 2 | 52.61 | 5 | 49.89 | ||||||||||||||||
|
Segment
loss before income taxes
|
$ | (12.53 | ) | (4 | ) | $ | (12.99 | ) | 11 | $ | (11.66 | ) | ||||||||
|
(1)
NGL volumes are converted to boe on a one-to-one basis with
oil.
|
|
(2)
Gas volumes are converted to barrel of oil equivalent (“boe”) at the rate
of six mcf of gas per barrel of oil, based upon the approximate relative
energy content of gas and oil, which rate is not necessarily indicative of
the relationship of oil and gas prices. Gran Tierra changed from the
conversion of gas volumes to boe at a rate of 20 mcf of gas per barrel of
oil to provide volume information consistent with standard industry
practice and to reflect natural gas’s relative energy content to a barrel
of oil. As a result, the 2007 boe volumes presented have increased by
3,107 boe from those volumes previously disclosed. Natural gas liquids
(“NGL”) volumes are converted to boe on a one-to-one basis with
oil.
|
50
|
(3)
|
Production
represents production volumes adjusted for inventory
changes.
|
Segmented
Results of Operations – Argentina for the Year Ended December 31, 2009 Compared
to the Results for the Year Ended December 31, 2008 and compared to the Results
for the Year Ended December 31, 2007
For the
2009 fiscal year, the
pre-tax
loss
from
Argentina was $4.2 million compared to pre-tax losses of $3.2 million and
$2.5 million recorded in fiscal years 2008 and 2007, respectively, due to higher
production levels offset partially by increased depletion. DD&A for 2009
included a $1.9 million ceiling test impairment loss in our Argentina cost
center. This impairment loss resulted from an increase in estimated future
operating costs to produce remaining proved reserves.
Crude oil and NGL
production
, net after 12% royalties, increased 39% to 337,316 barrels in
2009 compared to 242,947 barrels in 2008 and 207,912 barrels in 2007. The
increase resulted from the successful completion and testing of the Proa –
1 exploration well in the Surubi block in the third quarter of 2008 with sales
commencing in the fourth quarter of that year.
Due to
the local regulatory regimes, the price we currently receive for production from
our blocks is approximately $45 per barrel. 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,
2009. We are working with other oil and gas producers in the area, as well
as Refiner S.A., 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 $13.8 million generated in 2009 compares
to $9.6 million in 2008 and $8.1 million in 2007.
The
Argentine Secretariat of Energy has awarded Gran Tierra Argentina with $0.7
million of Petroleum Plus program fiscal credits due to our fourth quarter 2008
production growth. The program implements a system of fiscal credits calculated
on two different performance-based criteria: 1) production growth and 2)
replacement of total proved reserves, both over an established baseline
calculation of production additions and reserve replacement. The fiscal credits
are intended to be applied against export taxes. The Program was effective
October 1, 2008 and fiscal credits are awarded quarterly to companies meeting
the criteria on a “look back” basis. Annual requalification for the Petroleum
Plus program requires reserves replacement.
As our
Argentina subsidiary is not an exporter of oil, we are in the process of
identifying Argentine oil exporters who may wish to purchase this credit. Gran
Tierra considers the Petroleum Plus credits to be a contingent gain and
therefore no fiscal credits have been recorded in the financial statements.
Petroleum Plus fiscal credits will be recorded when they are received and
subsequently sold to an Argentine oil exporter. Amounts earned from fiscal
credits are fully taxable.
Operating
expenses
for the year ended December 31, 2009, increased slightly to
$7.5 million ($22.34 per boe) compared to $7.0 million ($28.92 per boe) and $6.3
million ($29.80 per boe), respectively, incurred in 2008 and 2007. Higher
production volumes from Proa – 1 in the Surubi block, in the comparative
periods, resulted in the significant reductions in the operating costs per
boe.
DD&A
expense
for 2009 was $8.3 million compared to $3.4 million in 2008 and $2.5 million in
2007. On a per boe basis, DD&A for the year ended December 31, 2009
increased to $24.72 from $13.95 and $11.66, respectively, recorded in 2008 and
2007. The impact of higher production levels and lower proved reserves was
partially offset by a decreasing proved depletable cost base. This decreasing
proved depletable cost base is a result of reduced development expenditures in
Argentina. In addition, DD&A for 2009 included a $1.9 million ceiling test
impairment loss in our Argentina cost center. This impairment loss resulted from
higher forecasted operating costs to produce remaining proved
reserves.
Capital
Program - Argentina
Capital
expenditures in 2009 amounted to $4.5 million mainly related to workovers,
facility construction, and the acquisition of seismic.
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.
51
Segmented
Results – Corporate
|
Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
% Change
|
2008
|
% Change
|
2007
|
||||||||||||||||
|
Segmented Results of Operations - Corporate
|
||||||||||||||||||||
|
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Interest
|
$ | 494 | 140 | $ | 206 | 10 | $ | 188 | ||||||||||||
|
Operating
expenses
|
156 | 111 | 74 | 48 | 50 | |||||||||||||||
|
Depletion,
depreciation and accretion
|
311 | 110 | 148 | 68 | 88 | |||||||||||||||
|
General
and administrative expenses
|
13,458 | 14 | 11,769 | 72 | 6,831 | |||||||||||||||
|
Liquidated
damages
|
- | - | - | (100 | ) | 7,367 | ||||||||||||||
|
Derivative
financial instruments (gain) loss
|
190 | 198 | (193 | ) | (106 | ) | 3,040 | |||||||||||||
|
Foreign
exchange gain
|
(319 | ) | (54 | ) | (698 | ) | 9,871 | (7 | ) | |||||||||||
| 13,796 | 24 | 11,100 | (36 | ) | 17,369 | |||||||||||||||
|
Segment
loss before income taxes
|
$ | (13,302 | ) | 22 | $ | (10,894 | ) | (37 | ) | $ | (17,181 | ) | ||||||||
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 regulations, the results of the Corporate Segment include
the results of our initial operations in Peru and Brazil.
G&A
Expenses
Increased
staffing levels to support business development activities and expanded
operations as well as higher stock-based compensation expense due to increased
stock option grants were the contributing factors to the three-year increase in
Corporate G&A. For 2008, the increase in G&A expenses from those
recorded in 2007 was also attributable to higher corporate stewardship
costs.
Derivative
Financial Instruments (Gain) Loss
|
Year Ended December 31,
|
||||||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008
|
2007
|
|||||||||
|
Realized financial
derivative (gain) loss
|
$ | (87 | ) | $ | 2,689 | $ | 391 | |||||
|
Unrealized
financial derivative (gain) loss
|
277 | (2,882 | ) | 2,649 | ||||||||
|
Derivative
financial instruments (gain) loss
|
$ | 190 | $ | (193 | ) | $ | 3,040 | |||||
|
As at December
31,
|
||||||||
|
Assets
(Liabilities)
|
2009
|
2008
|
||||||
|
Derivative
financial instruments
|
$ | (44 | ) | $ | 233 | |||
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, 2009, we recorded a loss of $0.2 million. This
compares to a gain of $0.2 million, and a $3.0 million loss from derivative
financial instruments, for the years ended December 31, 2008, and 2007,
respectively. These gains and losses are based on the effects of changing WTI
crude oil price, and forward price curves used to fair value the costless collar
at the respective year ends.
52
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.
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 $4.2 million in the value of warrants representing the fair value
determined using the Black-Scholes option pricing model using inputs similar to
those used for the company’s other equity instruments issued. The remaining $4.4
million liquidated damages settled through this warrant modification was
recorded to paid-in-capital. Liquidated damages of $8.6 million were expensed in
the results of operations of which $1.3 million was recorded in the first
quarter of 2006.
Foreign
Exchange Loss (Gain)
The
foreign exchange loss (gain) results from the translation of foreign currency
denominated transactions to U.S. Dollars.
Capital
Program – Corporate
The
capital expenditures for the Corporate Segment during the year ended December
31, 2009 were $2.2 million. These expenditures included $1.8 million
for Peru on our exploration blocks 122 and 128 for drilling feasibility and
geological studies.
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 were 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.
Fourth
Quarter Results
The
following table provides an analysis of quarterly financial information (in
thousands of dollars except production, per share and per BOE amounts) for the
three months ended December 31, 2009 compared to the same period in
2008:
|
Three Months Ended December 31,
|
||||||||
|
Selected Quarterly Financial Information
|
2009
|
2008
|
||||||
|
Production - Barrels of Oil
Equivalent per Day
|
14,714 | 4,094 | ||||||
|
Per
BOE Prices Realized
|
$ | 70.93 | $ | 50.27 | ||||
|
Revenue
and Other Income
|
$ | 96,286 | $ | 19,727 | ||||
|
Expenses
|
53,106 | 29,540 | ||||||
|
Income
(Loss) before Income Tax
|
43,180 | (9,813 | ) | |||||
|
Income
Tax Expense
|
12,355 | 2,881 | ||||||
|
Net
Income (Loss)
|
30,825 | (12,694 | ) | |||||
|
Basic
Earnings (Loss) per Share
|
$ | 0.13 | $ | (0.07 | ) | |||
|
Diluted
Earnings (Loss) per Share
|
$ | 0.12 | $ | (0.07 | ) | |||
For the
three months ended December 31, 2009, Gran Tierra recorded net income of $30.8
million ($0.13 per share basic and $0.12 per share diluted) compared to a loss
of $12.7 million (loss of $0.07 per share, basic and diluted) recorded in the
same period last year. The fourth quarter 2009 net income was positively
impacted by the increase in production and higher crude oil prices, partially
offset by the increase in expenses related to expanded operations. Fourth
quarter 2008 results were affected by the temporary suspension of production in
two major producing fields in Colombia. As a result, incremental revenues
contributed by Solana in 2008 were marginal due to the suspension of the
production in the fields which represent Solana’s major producing
properties.
Revenue
and other income for the fourth quarter of 2009 amounted to $96.3 million, an
increase of 388% from the same quarter last year. Higher production levels and
improved crude oil prices contributed to this significant increase. Production
of crude oil increased by 259% to 14,714 barrels per day from 4,094 barrels per
day in the last quarter of 2008. The positive effect of this increase in
production was offset slightly by the decline in crude oil prices. Average
prices per barrel of oil increased by 41% to $70.93 in the fourth quarter of
2009 from $50.27 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.
53
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. 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. Furthermore, DD&A for
2009 included a $1.9 million ceiling test impairment loss in our Argentina cost
center as previously discussed. The comparative results between the two quarters
were also affected by a foreign exchange gain of $12.6 million recorded in the
three months ended December 31, 2009 compared with a foreign exchange loss of
$8.0 million recorded in the same quarter of the previous year. These foreign
exchange gains and losses related to unrealized non-cash foreign exchange gains
or losses resulting primarily from the translation to U.S. dollars of a
Colombian Pesos denominated deferred tax liability recognized on the purchase of
Solana.
Liquidity
and Capital Resources
At
December 31, 2009, we had cash and cash equivalents of $270.8 million compared
to $176.8 million at December 31, 2008, and $18.2 million at December 31, 2007.
We believe that our cash position, together with positive cash flow from
operations and no debt, will provide us with sufficient liquidity to meet our
strategic objectives and fund our planned capital program for at least the next
12 months. In accordance with our 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. We believe
that our current financial position provides us the flexibility to respond to
both internal growth opportunities and those available through
acquisitions.
Gran
Tierra believes that it has sufficient available cash and cash flow from
operations to cover its expected funding needs on both a short-term and
long-term basis. If the need were to arise, Gran Tierra believes that it could
access short-term debt markets, to fund its short-term requirements and to
ensure near-term liquidity. Gran Tierra regularly monitors the credit and
financial markets and, in the future, may take advantage of what it believes are
favorable market conditions to issue long-term debt to further improve its
liquidity and capital resources. Gran Tierra’s long-term financing strategy is
to maintain continuous access to the debt markets to accommodate its long term
growth strategy.
Effective
February 28, 2007, we entered into a credit facility with Standard Bank
Plc. As a result of re-negotiations concluded in August 2009, the maximum amount
of the credit facility was increased to $200 million with a $7 million
borrowing base that could be re-determined semi-annually based on reserve
evaluation reports, but the maturity date was not extended. As a result of
Standard Bank Plc’s review of Gran Tierra’s 2008 Independent Reserve Audit, we
had the capacity to increase the borrowing base to $120 million under the
revised facility; however, this was not pursued further as the additional
borrowing base was not required. The facility included a letter of credit
sub-limit of $5 million. Amounts drawn down under the facility bear interest at
the Eurodollar rate plus 4%. A stand-by fee of 1% per annum was charged on the
un-drawn amount of the borrowing base. The facility is secured primarily by the
assets of Gran Tierra Colombia and Solana Petroleum Exploration (Colombia) Ltd.
Under the terms of the facility, Gran Tierra is required to maintain and
was in 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 June 30, 2006 Independent Reserve Evaluation Report projected aggregate
net share of Colombian production after royalties for the three-year term of the
Facility. As at December 31, 2009, no amount was drawn-down under this
facility.
The
forgoing facility expired February 22, 2010. Gran Tierra is
negotiating a facility with a major bank to replace the expired facility and we
currently intend to have this facility in place by the second quarter of
2010.
Cash
Flows
During
the year ended December 31, 2009, our cash and cash equivalents increased by
$94.0 million as cash inflows from operations of $165.5 million and from
financing activities of $4.9 million more than offset cash outflows for
investing activities of $76.4 million.
Net cash
provided by operating activities was affected by the significant increase in
crude oil production partially offset by the decrease in oil prices and increase
in receivables related to oil sales. The acquisition of Solana along with the
additional production from three new development wells in Colombia contributed
to the increased production. This increased oil revenue from higher production
volumes and a higher fourth quarter 2009 average oil price received, as compared
to the same quarter of the prior year, has resulted in our accounts receivable
increasing from the 2008 year end. This has been more than offset by an increase
in our accounts payable and accrued liabilities at year end as a result of
increased capital investment in oil and gas projects in Colombia. In addition,
in December 2008, our operations in Colombia were significantly restricted due
to a general strike which reduced our year end accounts receivable.
54
As
previously discussed, the increase in oil and gas property expenditures
primarily relate to continued development of our Costayaco field in Colombia and
the identification of new exploration prospects in all business units resulting
in the increase in cash used for investing activities. Cash provided by
financing activities relates to the exercise of outstanding warrants and
employee stock options.
For 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 included $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 the related 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.
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 related non-cash
working capital) expended in our capital expenditure program for our drilling
and other oilfield activities primarily in Colombia.
Off-Balance
Sheet Arrangements
As at
December 31, 2009, 2008 and 2007 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 $163,167 for office leases, $14,095 for vehicle
leases and $6,815 for certain employee accommodation leases in Colombia,
Argentina and Peru.
Future
lease payments and other contractual obligations at December 31, 2009 are as
follows:
|
As
at
December
31,
2009
|
||||||||||||||||||||
|
Payments
Due
in
Period
|
||||||||||||||||||||
|
Contractual Obligations
|
Total
|
Less
than
1
Year
|
1
to
3
years
|
3
to
5
years
|
More
than
5
years
|
|||||||||||||||
|
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||
|
Operating
leases
|
$ | 6,464 | $ | 2,047 | $ | 3,086 | $ | 1,331 | $ | - | ||||||||||
|
Software
and Telecommunication
|
1,835 | 1,209 | 626 | - | - | |||||||||||||||
|
Drilling,
Completion, Facility Construction and Oil Transportation
Services
|
24,985 | 24,882 | 103 | - | - | |||||||||||||||
|
Total
|
$ | 33,284 | $ | 28,138 | $ | 3,815 | $ | 1,331 | $ | - | ||||||||||
Contractual
commitments have increased $27.0 million from December 31, 2008 as a result of
increased operating leases ($1.3 million) increased software and
telecommunication contracts ($1.8 million) and entering into more third party
facility construction, oil transportation and drilling rig commitment contracts
($23.9 million), mainly in Colombia.
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 $9,900 per month and operating and other expenses
are approximately $4,100 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 $7,800 per month plus
approximately $4,000 for operating and other expenses. The terms of the
sublease were consistent with market conditions in the Calgary real estate
market.
Subsequent
Event
On
January 20, 2010, Gran Tierra issued 3,572,969 common shares upon the exercise
of 3,572,969 warrants issued upon the acquisition of Solana for $7.1 million or
$2.01 per share.
55
Outlook
Business
Environment
Our
revenues have been negatively impacted by the continuing fluctuations in crude
oil prices. Crude oil prices are volatile and unpredictable and are influenced
by concerns about financial markets and the impact of the downturn in the
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 and cash on hand, 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, disposition of assets, or issuance of equity.
The
credit markets, including the commercial paper markets in the United States,
have 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 issuing debt, 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.
Determination of the borrowing base under a new credit facility i
f any, will most likely be
dependent on our success in
maintaining or 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 pledging of some or
all of our assets
.
2010
Work Program and Capital Expenditure Program
Gran
Tierra’s 2010 work program is intended to create both growth and value in our
existing assets through increasing our reserves and production from exploration
financed by cash flow, while retaining financial flexibility with a strong cash
position and no debt, so that we can be positioned to undertake further
development opportunities and to pursue acquisition opportunities. However,
actual capital expenditures may vary significantly from our 2010 work program if
unexpected events or circumstances occur, such as new opportunities present
themselves, or anticipated opportunities do not come to fruition, which may
therefore either increase or decrease the amount of capital expenditures we
incur in 2010.
Excluding
potential exploration success, production in 2010 is expected to range between
14-16,000 BOPD net after royalty.
Gran
Tierra has planned a 2010 capital spending program of $195 million for
exploration and development activities in Colombia, Peru, Argentina and business
development activities in Brazil. Planned capital expenditures in Colombia are
$129 million, $41 million in Peru, and $23 million in Argentina.
We expect
that our committed and discretionary 2010 capital program can be funded from
cash flow from operations and cash on hand.
Outlook
– Colombia
The 2010
capital program in Colombia is $129 million. The majority (64%) of
the 2010 capital spending in Colombia is associated with exploration, which
includes the drilling of 7 exploration wells plus seismic acquisition programs
in 6 blocks to prepare drilling opportunities for 2011. The 2010 exploration
drilling program in Colombia includes the following wells:
|
|
·
|
Chaza
block: 1 exploration well;
|
|
|
·
|
Guayuyaco
block: 1 exploration well;
|
|
|
·
|
Azar
block: 2 exploration wells;
|
|
|
·
|
Rumiyaco
block: 1 exploration well;
|
|
|
·
|
Piedemonte
Sur: 1 exploration well;
|
|
|
·
|
Piedemonte
Norte: 1 exploration well.
|
The 2010
seismic acquisition in Colombia include the following programs:
|
|
·
|
Chaza
block: 70 km
2
3D;
|
|
|
·
|
Guayayaco
block: 40 km
2
3D;
|
|
|
·
|
Azar
block: 75 km
2
3D;
|
|
|
·
|
Rumiyaco
block: 95 km
2
3D
+ 12 km 2D;
|
|
|
·
|
Piedemonte
Norte block: 70 km 2D;
|
|
|
·
|
Piedemonte
Sur block: 10 km 2D.
|
56
In
addition to the above exploration activity we plan to spend approximately $47
million on development related activities which includes drilling one water
injector well in the Costayaco field and infrastructure improvements. New
infrastructure construction planned for the Costayaco field includes crude
gathering lines, water lines, pumping stations, storage batteries, crude
unloading facilities, water injection and disposal, and Costayaco
electrification and field support facilities. During 2010 upgrades to the
Santana pumping station are scheduled to continue, with the objective to improve
storage and pumping capacity.
Outlook
– Argentina
The 2010
capital program in Argentina is $23 million. Gran Tierra’s planned work program
for 2010 consists of a re-entry and sidetrack of one well in the Valle Morado
block, seismic acquisition in the Santa Victoria block, facilities upgrades, and
well workovers.
In the
Valle Morado block, a re-entry and sidetrack of the VM.x-1001 well is scheduled
for Q3 2010, for an estimated cost of $15 million. The sidetrack well is being
drilled to test the resource potential discovered by the VM.x-1001 well.
Existing pipeline and gas processing plant capacity is capable of handling 30
MMSCF/day.
In the
Santa Victoria block a 150 Km
2
3D and
200 Km 2D seismic acquisition program is planned for Q3 2010 to define
structural and stratigraphic traps in a gas-condensate trend identified from
existing seismic data.
The 2010
budget also includes approximately $4 million for workovers and facilities
upgrades on other Gran Tierra properties in the Noroeste Basin.
Outlook
- Peru
The 2010
capital program in Peru is $41 million. 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 more than 20 leads based on interpretation of
a 20,000 linear kilometer airborne gravity and magnetic survey completed over
the blocks in 2008. An environmental and social impact assessment has been
completed in preparation for initiating a 554 kilometer 2-D seismic acquisition
survey beginning in the second quarter of 2010 over the principal leads
identified on the two blocks. We are planning on drilling up to four
exploration wells beginning late in the second quarter of 2010 and continuing
into the second half of 2010.
Outlook
- Brazil
We
established a business development office in Brazil during August,
2009. We are currently undertaking the evaluation of a variety of
exploration and development new venture opportunities. An operating
budget of $2.4 million to continue this initiative in Brazil has been approved
for 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.
57
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 U.S. Securities and Exchange Commission (“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,
geo-physical, engineering and economic data.
To
estimate the economically recoverable oil and natural gas reserves and related
future net cash flows, we incorporate many factors and assumptions
including:
|
|
·
|
Expected
reservoir characteristics based on geological, geophysical and engineering
assessments
|
|
|
·
|
Future
production rates based on historical performance and expected future
operating and investment activities
|
|
|
·
|
Future
oil and gas quality differentials
|
|
|
·
|
Assumed
effects of regulation by governmental
agencies
|
|
|
·
|
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:
|
|
·
|
Determining
whether or not an exploratory well has found economically producible
reserves
|
|
|
·
|
Calculating
our unit-of-production depletion rates. Proved reserves estimates are used
to determine rates that are applied to each unit-of-production in
calculating our depletion expense.
|
|
|
·
|
Assessing,
when necessary, our oil and gas assets for impairment. Estimated future
cash flows are determined using proved reserves. The critical estimates
used to assess impairment, including the impact of changes in reserves
estimates, are discussed below.
|
Oil
and Gas Accounting and Impairment
The
accounting for and disclosure of oil and gas producing activities requires that
we choose between GAAP alternatives. We use the full cost method of accounting
for our oil and natural gas operations. Under this method, separate cost centers
are maintained for each country in which we incur costs. All costs incurred in
the acquisition, exploration and development of properties (including costs of
surrendered and abandoned leaseholds, delay lease rentals, dry holes and
overhead related to exploration and development activities) are capitalized. The
sum of net capitalized costs and estimated future development costs of oil and
natural gas properties for each full cost center are depleted using the
units-of-production method. Changes in estimates of proved reserves, future
development costs or asset retirement obligations are accounted for
prospectively in our depletion calculation.
Investments
in unproved properties are not depleted pending the determination of the
existence of proved reserves. Unproved properties are assessed periodically to
ascertain whether impairment has occurred. Unproved properties, the costs of
which are individually significant, are assessed individually by considering the
primary lease terms of the properties, the holding period of the properties, and
geographic and geologic data obtained relating to the properties. Where it is
not practicable to individually assess the amount of impairment of properties
for which costs are not individually significant, these properties are grouped
for purposes of assessing impairment. The amount of impairment assessed is added
to the costs to be amortized in the appropriate full cost pool.
Companies
that use the full cost method of accounting for oil and natural gas exploration
and development activities are required to perform a ceiling test calculation
each quarter on a country-by-country basis. The ceiling limits these pooled
costs to the aggregate of the after-tax, present value, discounted at 10%, of
future cash flows attributable to proved reserves, known as the standardized
measure, plus the lower of cost or market value of unproved properties less any
associated tax effects. Cash flow estimates for our impairment assessments
require assumptions about two primary elements — constant prices and reserves.
It is difficult to determine and assess the impact of a decrease in our proved
reserves on our impairment tests. The relationship between the reserves estimate
and the estimated discounted cash flows is complex because of the necessary
assumptions that need to be made regarding period end production rates, twelve
month unweighted average 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.
58
We
assessed our oil and gas properties for impairment as at December 31, 2009
and found no impairment write-down was required based on our assumptions for our
Colombia cost center. As a result of assessing our oil and gas property
impairment for our Argentina cost center, a ceiling test impairment loss of $1.9
million was recorded as a result of an increase in estimated future operating
costs to produce our remaining Argentine proved reserves. We assessed our oil
and gas properties for impairment as at December 31, 2008 and 2007 and
found no impairment write-downs were required based on our assumptions.
Estimates of standardized measure of our future cash flows from proved reserves
for our December 31, 2009 ceiling tests were based on realized crude oil prices
of $61.04 and $4.50 per mcf in Colombia and $40.98 for oil production in
Argentina and $2.90 per mcf for gas production in Argentina.
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 with the
assistance of 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 certain 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. This reporting segment
is not at risk of failing the “Step 1” goodwill impairment test under Financial
Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”)
350,
Intangibles
–
Goodwill and
Others
.
The
calculated fair value of the Colombian business unit was significantly in excess
of its book values.
59
Differences
in the our actual future cash flows, operating results, growth rates, capital
expenditures, cost of capital and discount rates as compared to the estimates
utilized for the purpose of calculating the fair value of each business unit, as
well as a decline in our stock price and related market capitalization, could
affect the results of our annual goodwill assessment and, accordingly,
potentially lead to future goodwill impairment charges.
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.
Our
effective tax rate is based on pre-tax income and the tax rates applicable to
that income in the various jurisdictions in which we operate. An estimated
effective tax rate for the year is applied to our quarterly operating results.
In the event that there is a significant unusual or discrete item recognized, or
expected to be recognized, in the our quarterly operating results, the tax
attributable to that item would be separately calculated and recorded at the
same time as the unusual or discrete item. We consider the resolution of
prior-year tax matters to be such items. Significant judgment is required in
determining our effective tax rate and in evaluating our tax positions. We
establish reserves when it is more likely than not that we will not realize the
full tax benefit of the position. We adjust these reserves in light of changing
facts and circumstances.
Share-Based
Payment Arrangements
We record
share-based payment arrangements in accordance with the ASC 718,
Compensation – Stock
Compensation
, 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.
ASC 718
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 ASC
718, 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. ASC 718 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 ASC
718, 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. We are responsible
for determining the assumptions used in estimating the fair value of our
share-based payment awards.
Warrants
We follow
the fair-value method of accounting for warrants issued to purchase our common
stock. The change of $4.2 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 option pricing model using inputs similar to
those used for Gran Tierra’s issued equity instruments
issued.
60
New
Accounting Pronouncements
Framework
for Fair Value Measurement
In
February 2008, the Financial Accounting Standards Board (“FASB”) issued guidance
related to the application of the framework for fair value measurement to
non-financial assets and non-financial liabilities. The FASB decided to delay
the effective date of applying the framework for fair value measurement to
non-financial assets and non-financial liabilities until fiscal years beginning
after November 15, 2008, and interim periods within those fiscal years,
except for items that are recognized or disclosed at fair value in the financial
statements on a recurring basis. The implementation of this guidance, effective
January 1, 2009, did not materially impact Gran Tierra’s consolidated
financial position, results of operations or cash flows.
Business
Combinations
In
December 2007, the FASB issued accounting standards which require the acquiring
entity in a business combination to recognize all (and only) the assets acquired
and liabilities assumed in the transaction; establish the acquisition date fair
value as the measurement objective for all assets acquired and liabilities
assumed; and disclose to investors and other users all of the information they
need to evaluate and understand the nature and financial effect of the business
combination. In April 2009, the FASB issued guidance to address application
issues raised by preparers, auditors and members of the legal profession on
initial recognition and measurement, subsequent measurement and accounting, and
disclosure of assets and liabilities arising from contingencies in a business
combination. These standards were applied prospectively. The implementation of
these standards, effective January 1, 2009, did not materially impact Gran
Tierra’s consolidated financial position, results of operations or cash
flows.
Derivative
Instruments and Hedging Activities
In March
2008, the FASB issued accounting standards that require enhanced disclosures
about an entity’s derivative and hedging activities. Entities are required to
provide disclosures about (i) how and why an entity uses derivative
instruments, (ii) how derivative instruments and related hedged items are
accounted for, and (iii) how derivative instruments and related hedged
items affect an entity’s financial position, financial performance and cash
flows. The standards increase convergence with International Financial Reporting
Standards (“IFRS”), as it relates to disclosures of derivative instruments. The
implementation of these standards, effective January 1, 2009, did not
materially impact Gran Tierra’s consolidated financial position, results of
operations or cash flows.
The
SEC Modernization of Oil and Gas Reporting
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. Gran Tierra has adopted the
provisions of this final ruling for disclosures in the financial statements
included in this Annual Report on Form 10-K for the year ending December 31,
2009. The implementation of this rule did not materially impact Gran
Tierra’s disclosures, operating results, financial position and cash
flows.
Fair
Value Measurement in Inactive Markets and Distressed
Transactions
In April
2009, the FASB issued guidance for estimating fair value in accordance with the
framework for fair value measurement, when the volume and level of activity for
the asset or liability have significantly decreased. At the same time the FASB
issued guidance on identifying circumstances that indicate a transaction is not
orderly. The standard was applied prospectively. The implementation of this
standard, effective for interim periods ending after June 15, 2009, did not
materially impact Gran Tierra’s consolidated financial position, operating
results and cash flows.
Subsequent
Events
In May
2009, the FASB issued standards addressing subsequent events. The standards
address the recognition and disclosure of events that occur after the balance
sheet date but before the issuance of the financial statements. The FASB issued
the standards in order to incorporate, within the accounting standards,
principles that had originated in auditing standards. The standards also require
an entity to disclose the date through which subsequent events have been
evaluated, as well as whether that date is the date the financial statements
were issued or the date the financial statements were available to be issued.
The standards do not differ significantly from previously applied standards on
disclosure of subsequent events. Gran Tierra implemented these standards
prospectively on June 30, 2009. The standards did not have a material
impact on Gran Tierra’s consolidated financial position, operating results and
cash flows. Gran Tierra has evaluated subsequent events through
February
26
, 2010
, the date the financial
statements were issued, and noted no subsequent events that required
disclosure.
61
FASB
Accounting Standards Codification
On
July 1, 2009, the FASB issued the FASB Accounting Standards Codification
(the “Codification”) as the single source of authoritative US GAAP (other than
guidance issued by the SEC), superseding existing FASB, American Institute of
Certified Public Accountants, Emerging Issues Task Force, and related
literature. The Codification was applied on September 30, 2009. Now, only
one level of authoritative US GAAP exists. All other literature is considered
non-authoritative. The Codification does not change US GAAP; instead, it
introduced a new structure that is organized in an online research system. The
Codification did not have an impact on Gran Tierra’s consolidated financial
statements.
Measuring
Liabilities at Fair Value
In August
2009, the FASB issued Accounting Standards Update, "Measuring Liabilities at
Fair Value," This update provides clarification for circumstances in which a
quoted price in an active market for the identical liability is not
available. In such circumstances, an entity is required to measure
fair value that uses (1) the quoted price of the identical liability when traded
as an asset, or (2) quoted prices for similar liabilities or similar liabilities
when traded as assets, or (3) another valuation technique consistent with the
fair value measurement principles such as an income approach or a market
approach. The implementation of this update October 1, 2009 did not
materially impact Gran Tierra’s consolidated financial position, operating
results and cash flows.
Variable
Interest Entities
In June
2009, the FASB issued revised accounting standards to improve financial
reporting by enterprises involved with variable interest entities. The standards
replace the quantitative-based risks and rewards calculation for determining
which enterprise, if any, has a controlling financial interest in a variable
interest entity with an approach focused on identifying which enterprise has the
power to direct the activities of a variable interest entity that most
significantly impact the entity’s economic performance and: (1) the
obligation to absorb losses of the entity; or, (2) the right to receive
benefits from the entity. The standards will be implemented prospectively on
January 1, 2010. Gran Tierra is currently reviewing the impact, if any, on
Gran Tierra’s consolidated financial statements.
Gran
Tierra has reviewed all other recently issued, but not yet adopted, accounting
standard updates in order to determine their effects, if any, on its
consolidated financial statements. Based on that review, Gran Tierra believes
that the implementation of these standards will not materially impact Gran
Tierra’s consolidated financial position, operating results or cash
flows.
Our
principal market risk relates to oil prices. Essentially 100% of our revenues
are from oil sales at prices which are defined by contract relative to WTI 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, and which expired February 22, 2010,
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. At December 31,
2009, this costless collar represented a liability of $44,000, compared to an
asset of $233,000 at December 31, 2008. A hypothetical 10% increase in WTI price
on December 31, 2009 would cause the value to increase by approximately $81,000,
and a hypothetical 10% decrease in WTI price on December 31, 2009 would cause
the value to decrease by approximately $38,000. This compares to 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 as we hold only
cash and cash equivalents. Interest rate exposures relate entirely to our
investment portfolio, as we do not have short term or long term debt. 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 until December 2009, we received 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 has been approximately balanced
between U.S. and peso expenditures, providing a natural currency hedge. In the
future we will receive 100% of our revenue in Colombia in U.S. dollars. 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.
62
Additionally,
foreign exchange gains/losses result from the fluctuation of the U.S. dollar to
the Colombian peso due to our deferred tax liability, a monetary liability,
which is mainly denominated in the local currency of the Colombian foreign
operations. As a result, a foreign exchange gain/loss must be calculated on
conversion to the U.S. dollar functional currency. A strengthening in the
Colombian peso against the U.S. dollar results in foreign exchange losses,
estimated at $99,000 for each one peso decrease in the exchange rate of the
Colombian peso to one U.S. dollar.
63
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 at December 31, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their
cash flows for each of the three years in the period ended December 31,
2009 in accordance 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 of December 31, 2009, 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
26
, 2010
, expressed an unqualified
opinion on the Company’s internal control over financial reporting.
/s/
Deloitte & Touche LLP
Independent
Registered Chartered Accountants
Calgary,
Canada
February
26
, 2010
64
Gran
Tierra Energy Inc.
For
the Years Ended December 31, 2009, 2008 and 2007
(Thousands
of U.S. Dollars, Except Share and Per Share Amounts)
|
Year
Ended
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
REVENUE
AND OTHER INCOME
|
||||||||||||
|
Oil
and natural gas sales
|
$ | 262,629 | $ | 112,805 | $ | 31,853 | ||||||
|
Interest
|
1,087 | 1,224 | 425 | |||||||||
| 263,716 | 114,029 | 32,278 | ||||||||||
|
EXPENSES
|
||||||||||||
|
Operating
|
40,784 | 19,218 | 10,474 | |||||||||
|
Depletion,
depreciation and accretion
|
135,863 | 25,737 | 9,415 | |||||||||
|
General
and administrative
|
28,787 | 18,593 | 10,232 | |||||||||
|
Liquidated
damages (Note 6)
|
- | - | 7,367 | |||||||||
|
Derivative
financial instruments (gain) loss (Note 11)
|
190 | (193 | ) | 3,040 | ||||||||
|
Foreign
exchange (gain) loss
|
19,797 | 6,235 | (78 | ) | ||||||||
| 225,421 | 69,590 | 40,450 | ||||||||||
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
38,295 | 44,439 | (8,172 | ) | ||||||||
|
Income
tax expense (Note 8)
|
(24,354 | ) | (20,944 | ) | (295 | ) | ||||||
|
NET
INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
|
13,941 | 23,495 | (8,467 | ) | ||||||||
|
RETAINED
EARNINGS (ACCUMULATED DEFICIT), BEGINNING OF YEAR
|
6,984 | (16,511 | ) | (8,044 | ) | |||||||
|
RETAINED
EARNINGS (ACCUMULATED DEFICIT), END OF YEAR
|
$ | 20,925 | $ | 6,984 | $ | (16,511 | ) | |||||
|
NET
INCOME (LOSS) PER SHARE — BASIC
|
$ | 0.06 | $ | 0.19 | $ | (0.09 | ) | |||||
|
NET
INCOME (LOSS) PER SHARE — DILUTED
|
$ | 0.05 | $ | 0.16 | $ | (0.09 | ) | |||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING - BASIC (Note 6)
|
241,258,568 | 123,421,898 | 95,096,311 | |||||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)
|
253,590,103 | 143,194,590 | 95,096,311 | |||||||||
(See
notes to the consolidated financial statements)
65
Gran
Tierra Energy Inc.
As
at December 31, 2009 and 2008
(Thousands of U.S. Dollars)
|
As
at
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
and cash equivalents
|
$ | 270,786 | $ | 176,754 | ||||
|
Restricted
cash
|
1,630 | - | ||||||
|
Accounts
receivable
|
35,639 | 7,905 | ||||||
|
Inventory
(Note 2)
|
4,879 | 999 | ||||||
|
Taxes
receivable
|
1,751 | 5,789 | ||||||
|
Prepaids
|
1,820 | 1,103 | ||||||
|
Derivative
financial instruments (Note 11)
|
- | 233 | ||||||
|
Deferred
tax assets (Note 8)
|
4,252 | 2,262 | ||||||
|
Total
Current Assets
|
320,757 | 195,045 | ||||||
|
Oil
and Gas Properties (using the full cost method of
accounting)
|
||||||||
|
Proved
|
474,679 | 380,855 | ||||||
|
Unproved
|
234,889 | 384,195 | ||||||
|
Total
Oil and Gas Properties
|
709,568 | 765,050 | ||||||
|
Other
capital assets
|
3,175 | 2,502 | ||||||
|
Total
Property, Plant and Equipment (Note 5)
|
712,743 | 767,552 | ||||||
|
Other
Long Term Assets
|
||||||||
|
Restricted
cash
|
162 | - | ||||||
|
Deferred
tax assets (Note 8)
|
7,218 | 10,131 | ||||||
|
Other
long term assets
|
347 | 1,315 | ||||||
|
Goodwill
(Note 3)
|
102,581 | 98,582 | ||||||
|
Total
Other Long Term Assets
|
110,308 | 110,028 | ||||||
|
Total
Assets
|
$ | 1,143,808 | $ | 1,072,625 | ||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable (Note 9)
|
$ | 36,786 | $ | 21,134 | ||||
|
Accrued
liabilities (Note 9)
|
40,229 | 12,841 | ||||||
|
Derivative
financial instruments (Note 11)
|
44 | - | ||||||
|
Taxes
payable
|
28,087 | 28,163 | ||||||
|
Deferred
tax liability (Note 8)
|
- | 100 | ||||||
|
Asset
retirement obligation (Note 7)
|
450 | - | ||||||
|
Total
Current Liabilities
|
105,596 | 62,238 | ||||||
|
Long
Term Liabilities
|
||||||||
|
Deferred
tax liability (Note 8)
|
216,625 | 213,093 | ||||||
|
Deferred
remittance tax (Note 8)
|
903 | 1,117 | ||||||
|
Asset
retirement obligation (Note 7)
|
4,258 | 4,251 | ||||||
|
Total
Long Term Liabilities
|
221,786 | 218,461 | ||||||
|
Commitments
and Contingencies (Note 10)
|
||||||||
|
Subsequent
Event (Note 14)
|
||||||||
|
Shareholders’
Equity
|
||||||||
|
Common
shares (Note 6)
|
1,431 | 226 | ||||||
|
(219,459,361
and 190,248,384 common shares and 24,639,513 and 48,238,269 exchangeable
shares, par value $0.001 per share, issued and outstanding as at December
31, 2009 and 2008 respectively)
|
||||||||
|
Additional
paid in capital
|
766,963 | 754,832 | ||||||
|
Warrants
|
27,107 | 29,884 | ||||||
|
Retained
earnings
|
20,925 | 6,984 | ||||||
|
Total
Shareholders’ Equity
|
816,426 | 791,926 | ||||||
|
Total
Liabilities and Shareholders’ Equity
|
$ | 1,143,808 | $ | 1,072,625 | ||||
(See
notes to the consolidated financial statements)
66
Gran
Tierra Energy Inc.
For
the Years Ended December 31, 2009, 2008 and 2007
(Thousands of U.S. Dollars)
|
Year
Ended
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Operating
Activities
|
||||||||||||
|
Net
income (loss)
|
$ | 13,941 | $ | 23,495 | $ | (8,467 | ) | |||||
|
Adjustments
to reconcile net income (loss) to net cash provided by operating
activities:
|
||||||||||||
|
Depletion,
depreciation and accretion
|
135,863 | 25,737 | 9,415 | |||||||||
|
Deferred
taxes
|
(15,355 | ) | (6,418 | ) | 185 | |||||||
|
Stock
based compensation
|
5,309 | 2,520 | 810 | |||||||||
|
Liquidated
damages
|
- | - | 5,839 | |||||||||
|
Unrealized
(gain) loss on financial instruments (Note 11)
|
277 | (2,882 | ) | 2,649 | ||||||||
|
Unrealized
foreign exchange loss
|
19,496 | 6,985 | - | |||||||||
|
Settlement
of asset retirement obligations (Note 7)
|
(52 | ) | (334 | ) | - | |||||||
|
Net
changes in non-cash working capital
|
||||||||||||
|
Accounts
receivable
|
(27,926 | ) | 34,943 | (5,604 | ) | |||||||
|
Inventory
|
(1,849 | ) | (107 | ) | 25 | |||||||
|
Prepaids
|
(717 | ) | 261 | 234 | ||||||||
|
Accounts
payable and accrued liabilities
|
36,875 | 10,697 | 2,807 | |||||||||
|
Taxes
receivable and payable
|
(409 | ) | 14,840 | 869 | ||||||||
|
Net
cash provided by operating activities
|
165,453 | 109,737 | 8,762 | |||||||||
|
Investing
Activities
|
||||||||||||
|
Restricted
cash
|
(1,792 | ) | - | 1,010 | ||||||||
|
Additions
to property, plant and equipment
|
(80,932 | ) | (55,217 | ) | (15,976 | ) | ||||||
|
Proceeds
from disposition of oil and gas property (Note 5)
|
5,400 | - | - | |||||||||
|
Cash
acquired on acquisition net of acquisition costs (Note 3)
|
- | 81,912 | - | |||||||||
|
Long
term assets and liabilities
|
968 | 446 | (427 | ) | ||||||||
|
Net
cash provided by (used in) investing activities
|
(76,356 | ) | 27,141 | (15,393 | ) | |||||||
|
Financing
Activities
|
||||||||||||
|
Proceeds
from issuance of common stock
|
4,935 | 21,687 | 719 | |||||||||
|
Net
cash provided by financing activities
|
4,935 | 21,687 | 719 | |||||||||
|
Net
increase (decrease) in cash and cash equivalents
|
94,032 | 158,565 | (5,912 | ) | ||||||||
|
Cash
and cash equivalents, beginning of year
|
176,754 | 18,189 | 24,101 | |||||||||
|
Cash
and cash equivalents, end of year
|
$ | 270,786 | $ | 176,754 | $ | 18,189 | ||||||
|
Cash
|
$ | 182,197 | $ | 110,688 | $ | 18,189 | ||||||
|
Term
deposits
|
88,589 | 66,066 | - | |||||||||
|
Cash
and cash equivalents, end of year
|
$ | 270,786 | $ | 176,754 | $ | 18,189 | ||||||
|
Supplemental
cash flow disclosures:
|
||||||||||||
|
Cash
paid for interest
|
$ | - | $ | - | $ | 80 | ||||||
|
Cash
paid for taxes
|
$ | 31,527 | $ | 11,587 | $ | 116 | ||||||
|
Non-cash
investing activities:
|
||||||||||||
|
Non-cash
working capital related to property, plant and equipment
|
$ | 17,972 | $ | 11,096 | $ | 8,259 | ||||||
(See
notes to the consolidated financial statements)
67
Gran
Tierra Energy Inc.
Consolidated
Statements of Shareholders’ Equity
For
the Years Ended December 31, 2009, 2008 and 2007
(Thousands
of U.S. Dollars)
|
Year
Ended
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Share
Capital
|
||||||||||||
|
Balance,
beginning of year
|
$ | 226 | $ | 95 | $ | 95 | ||||||
|
Issue
of common shares
|
1,205 | 131 | 1 | |||||||||
|
Cancelled
common shares
|
- | - | (1 | ) | ||||||||
|
Balance,
end of year
|
1,431 | 226 | 95 | |||||||||
|
Additional
Paid in Capital
|
||||||||||||
|
Balance,
beginning of year
|
754,832 | 76,805 | 71,311 | |||||||||
|
Cancelled
common shares
|
- | - | (1,086 | ) | ||||||||
|
Issue
of common shares
|
2,650 | 663,405 | 719 | |||||||||
|
Issue
of stock options in a business combination (Note 3)
|
- | 1,345 | - | |||||||||
|
Issue
of warrants (Restated – Note 6)
|
- | - | 4,453 | |||||||||
|
Exercise
of warrants (Restated – Note 6)
|
2,777 | 10,113 | 407 | |||||||||
|
Exercise
of stock options
|
1,080 | 72 | - | |||||||||
|
Stock
based compensation expense
|
5,624 | 3,092 | 1,001 | |||||||||
|
Balance,
end of year
|
766,963 | 754,832 | 76,805 | |||||||||
|
Warrants
|
||||||||||||
|
Balance,
beginning of year
|
29,884 | 16,403 | 12,832 | |||||||||
|
Cancelled
warrants
|
- | - | (233 | ) | ||||||||
|
Issue
of warrants (Note 3) (Restated – Note 6)
|
- | 23,594 | 4,172 | |||||||||
|
Exercise
of warrants (Restated – Note 6)
|
(2,777 | ) | (10,113 | ) | (368 | ) | ||||||
|
Balance,
end of year
|
27,107 | 29,884 | 16,403 | |||||||||
|
Retained
Earnings (Accumulated Deficit)
|
||||||||||||
|
Balance,
beginning of year
|
6,984 | (16,511 | ) | (8,044 | ) | |||||||
|
Net
income (loss)
|
13,941 | 23,495 | (8,467 | ) | ||||||||
|
Balance,
end of year
|
20,925 | 6,984 | (16,511 | ) | ||||||||
|
Total
Shareholders’ Equity
|
$ | 816,426 | $ | 791,926 | $ | 76,792 | ||||||
(See
notes to the consolidated financial statements)
68
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. 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, Peru and
Brazil.
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
of oil and gas properties and goodwill, 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, Peru and Brazil, 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, restricted cash,
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.
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
Restricted
cash relates to cash resources pledged to secure letters of
credit. All letters of credit currently secured by cash relate to
requirements for work commitment guarantees contained in exploration
contracts.
69
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
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 $0.3 and $0.4 million at December 31, 2009 and 2008,
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 lower of cost or market.
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, 2009
and 2008 are $3.8 million and $0.8 million, respectively. Supplies at December
31, 2009 and 2008 are $1.1 and $0.2 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.
Unproved
properties are evaluated quarterly for possible impairments. If impairment has
occurred, the impairment is transferred to proved properties and thus subject to
amortization immediately. For prospects where a reserve base has not yet been
established, the impairment is charged to earnings. 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.
The
Company performs a ceiling test calculation each quarter in accordance with the
U.S. Securities and 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. As a result of implementing 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 as at December 31, 2009, the Company
calculates future net cash flows by applying the 12 month period unweighted
arithmetic average of the price as of the first day of each month within that 12
month period, unless prices are defined by contractual arrangements, excluding
escalations based on future conditions. In prior years, the Company determined
future net cash flows by applying those prices in effect for each country at the
end of the reporting period.
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.
70
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
The
amortization of the asset retirement cost and the accretion of the asset
retirement obligation are included in depletion, depreciation and accretion
(“DD&A”). 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 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.
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 certain 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, 2009 and 2008.
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 an uncertain tax position is a two-step process. The first step is
recognition: The Company determines whether it is more likely than not that a
tax position will be sustained upon examination, including resolution of any
related appeals or litigation processes, based on the technical merits of the
position. In evaluating whether a tax position has met the more-likely-than-not
recognition threshold, the Company presumes that the position will be examined
by the appropriate taxing authority that has full knowledge of all relevant
information. The second step is measurement: A tax position that meets the
more-likely-than-not recognition threshold is measured to determine the amount
of benefit to recognize in the financial statements. The tax position is
measured at the largest amount of benefit that is greater than 50 percent likely
of being realized upon settlement. The Company recognizes potential accrued
interest and penalties related to unrecognized tax benefits as a component of
income tax expense in the consolidated statement of operations. This is an
accounting policy election made by the Company that is a continuation of the
Company’s historical policy and will continue to be consistently applied in the
future.
71
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Income
(loss) per share
Basic
income (loss) per share calculations are based on the net income (loss)
attributable to common shareholders for the period divided by the weighted
average number of common shares issued and outstanding during the period. The
diluted income (loss) per share calculation is based on the weighted average
number of common shares outstanding during the period, plus the effects of
dilutive common share equivalents. This method requires that the dilutive effect
of outstanding options and warrants issued should be calculated using the
treasury stock method. This method assumes that all common share equivalents
have been exercised at the beginning of the period (or at the time of issuance,
if later), and that the funds obtained thereby were used to purchase common
shares of the Company at the average trading price of common shares during the
period.
Stock-based
compensation
The
Company follows the fair-value based method of accounting for stock options
granted to directors, officers and employees. Compensation expense for options
granted is based on the estimated fair value, using the Black-Scholes option
pricing model, at the time of grant and the expense is recognized over the
requisite service period of the option. Stock-based compensation expense is
included as part of oil and natural gas properties, operating expenses, and
general and administrative expenses with a corresponding increase to contributed
surplus and recognized using the accelerated method.
Accounting
for oil and gas derivative instruments
The
Company recognizes all derivative instruments as either assets or liabilities at
fair value in its financial statements. 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 $4.2 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 (Note 6). 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
Framework
for Fair Value Measurement
In
February 2008, the Financial Accounting Standards Board (“FASB”) issued guidance
related to the application of the framework for fair value measurement to
non-financial assets and non-financial liabilities. The FASB decided to delay
the effective date of applying the framework for fair value measurement to
non-financial assets and non-financial liabilities until fiscal years beginning
after November 15, 2008, and interim periods within those fiscal years,
except for items that are recognized or disclosed at fair value in the financial
statements on a recurring basis. The implementation of this guidance, effective
January 1, 2009, did not materially impact the Company’s consolidated
financial position, results of operations or cash flows.
Business
Combinations
In
December 2007, the FASB issued accounting standards which require the acquiring
entity in a business combination to recognize all (and only) the assets acquired
and liabilities assumed in the transaction; establish the acquisition date fair
value as the measurement objective for all assets acquired and liabilities
assumed; and disclose to investors and other users all of the information they
need to evaluate and understand the nature and financial effect of the business
combination. In April 2009, the FASB issued guidance to address application
issues raised by preparers, auditors and members of the legal profession on
initial recognition and measurement, subsequent measurement and accounting, and
disclosure of assets and liabilities arising from contingencies in a business
combination. These standards were applied prospectively. The implementation of
these standards, effective January 1, 2009, did not impact the Company’s
consolidated financial position, results of operations or cash
flows.
72
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Derivative
Instruments and Hedging Activities
In March
2008, the FASB issued accounting standards that require enhanced disclosures
about an entity’s derivative and hedging activities. Entities are required to
provide disclosures about (i) how and why an entity uses derivative
instruments, (ii) how derivative instruments and related hedged items are
accounted for, and (iii) how derivative instruments and related hedged
items affect an entity’s financial position, financial performance and cash
flows. The standards increase convergence with IFRS, as it relates to
disclosures of derivative instruments. The implementation of these standards,
effective January 1, 2009, did not materially impact the Company’s
consolidated financial position, results of operations or cash flows. Expanded
disclosures are included in Note 11.
The SEC
Modernization of Oil and Gas Reporting
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 Company has adopted the
provisions of this final ruling for disclosures in these financial statements
included in the Annual Report on Form 10-K for the year ending December 31,
2009. The implementation, applied prospectively from December 31, 2009, of
this rule did not materially impact the Company’s disclosures, operating
results, financial position or cash flows.
Fair
Value Measurement in Inactive Markets and Distressed
Transactions
In April
2009, the FASB issued guidance for estimating fair value in accordance with the
framework for fair value measurement, when the volume and level of activity for
the asset or liability have significantly decreased. At the same time the FASB
issued guidance on identifying circumstances that indicate a transaction is not
orderly. The standard was applied prospectively. The implementation of this
standard, effective for interim periods ending after June 15, 2009, did not
materially impact the Company’s consolidated financial position, operating
results or cash flows.
Subsequent
Events
In May
2009, the FASB issued standards addressing subsequent events. The standards
address the recognition and disclosure of events that occur after the balance
sheet date but before the issuance of the financial statements. The FASB issued
the standards in order to incorporate, within the accounting standards,
principles that had originated in auditing standards. The standards also require
an entity to disclose the date through which subsequent events have been
evaluated, as well as whether that date is the date the financial statements
were issued or the date the financial statements were available to be issued.
The standards do not differ significantly from previously applied standards on
disclosure of subsequent events. The Company implemented these standards
prospectively on June 30, 2009. The standards did not have a material
impact on the Company’s consolidated financial position, operating results and
cash flows. The Company has evaluated subsequent events
through
February
26
,
2010
, the
date the financial statements were issued, and
noted no subsequent events that required disclosure.
FASB
Accounting Standards Codification
On
July 1, 2009, the FASB issued the FASB Accounting Standards Codification
(the “Codification”) as the single source of authoritative US GAAP (other than
guidance issued by the SEC), superseding existing FASB, American Institute of
Certified Public Accountants, Emerging Issues Task Force, and related
literature. The Codification was applied on September 30, 2009. Now, only
one level of authoritative US GAAP exists. All other literature is considered
non-authoritative. The Codification is not intended to change US GAAP; instead,
it introduced a new structure that is organized in an online research system.
The Codification did not have an impact on the Company’s consolidated financial
statements.
Measuring
Liabilities at Fair Value
In August
2009, the FASB issued Accounting Standards Update, "Measuring Liabilities at
Fair Value," This update provides clarification for circumstances in which a
quoted price in an active market for the identical liability is not
available. In such circumstances, an entity is required to measure
fair value that uses (1) the quoted price of the identical liability when traded
as an asset, or (2) quoted prices for similar liabilities or similar liabilities
when traded as assets, or (3) another valuation technique consistent with the
fair value measurement principles such as an income approach or a market
approach. The implementation of this update on October 1, 2009 did
not materially impact the Company’s consolidated financial position, operating
results or cash flows.
73
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Variable
Interest Entities
In June
2009, the FASB issued revised accounting standards to improve financial
reporting by enterprises involved with variable interest entities. The standards
replace the quantitative-based risks and rewards calculation for determining
which enterprise, if any, has a controlling financial interest in a variable
interest entity with an approach focused on identifying which enterprise has the
power to direct the activities of a variable interest entity that most
significantly impact the entity’s economic performance and: (1) the
obligation to absorb losses of the entity; or, (2) the right to receive
benefits from the entity. The standards will be implemented prospectively on
January 1, 2010. The Company is currently reviewing the impact, if any, on
the Company’s consolidated financial statements.
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, an international
resource company engaged in the acquisition, exploration, development and
production of oil and natural gas in Colombia with its head office located in
Calgary, Alberta, Canada. Under the terms of the agreement with Solana,
each Solana shareholder received, 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”). The
exchangeable shares: (a) have the same voting rights, dividend entitlements and
other attributes as Gran Tierra common stock; (b) are exchangeable, at each
stockholder's option, on a one-for-one basis into Gran Tierra common stock.
Exchangeable shares, issued upon the acquisition, are listed on the Toronto
Stock Exchange under the symbol GTX and will automatically be exchanged for Gran
Tierra common stock five years from closing, and in certain other events. In
addition, certain Solana options were exchanged for options of Gran Tierra based
on the above exchange ratio, and holders of Solana warrants elected to continue
to hold their warrants, which are exercisable into shares of common stock of
Gran Tierra pursuant to the terms of such warrants and based on the above
exchange ratio.
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.
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
|
Exercise
price (Canadian dollars per warrant)
|
$ | 2.00 | ||
|
Risk-free
interest rate
|
2.28 | % | ||
|
Expected
life
|
1.7
years
|
|||
|
Volatility
|
75 | % | ||
|
Expected
annual dividend per share
|
Nil
|
|||
|
Fair
value per warrant
|
$ | 3.39 | ||
74
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Stock
Options
|
Exercise
price (Canadian dollars per stock option)
|
$ | 2.36-$4.33 | ||
|
Risk-free
interest rate
|
2.28 | % | ||
|
Expected
life
|
1.3-4.8
years
|
|||
|
Volatility
|
71% - 75 | % | ||
|
Expected
annual dividend per share
|
Nil
|
|||
|
Weighted
average fair value per option
|
$ | 2.75 | ||
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.
The
following table shows the allocation of the purchase price based on the fair
values of the assets and liabilities acquired:
|
(Thousands of U.S. Dollars)
|
||||
|
Purchase
Price:
|
||||
|
Common
Shares/Exchangeable Shares issued net of share issue costs
|
$ | 631,451 | ||
|
Warrants
|
23,594 | |||
|
Stock
options
|
1,345 | |||
|
Two
million common shares issued under Colombian Participation
Agreement
|
10,470 | |||
|
Transaction
costs
|
4,938 | |||
| $ | 671,798 | |||
|
Purchase
Price Allocated:
|
||||
|
Oil
and Gas Properties
|
||||
|
Proved
|
$ | 320,773 | ||
|
Unproved
|
360,493 | |||
|
Other
assets
|
1,113 | |||
|
Other
long-term assets
|
1,329 | |||
|
Goodwill
(1)(2)
|
87,576 | |||
|
Net
working capital (including cash acquired)(2)
|
95,356 | |||
|
Asset
retirement obligations
|
(3,148 | ) | ||
|
Deferred
income taxes
|
(191,694 | ) | ||
| $ | 671,798 | |||
|
|
(1)
|
Goodwill
is not deductible for tax purposes and is subject to annual impairment
test.
|
|
|
(2)
|
Due
to new information received during 2009, the Company reclassified $4.4
million from taxes payable to goodwill in the purchase price allocation
relating to the Solana acquisition.
|
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. Pro forma results are not
indicative of actual results or future performance.
75
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
|
Year Ended December 31,
|
||||||||
|
(Unaudited) (Thousands of U.S. Dollars Except Per Share Amounts)
|
2008
|
2007
|
||||||
|
Oil
and natural gas sales and interest
|
$ | 221,043 | $ | 51,664 | ||||
|
Net
income (loss)
|
$ | 66,886 | $ | (22,315 | ) | |||
|
Net
income (loss) per share -basic
|
$ | 0.29 | $ | (0.10 | ) | |||
|
Net
income (loss) per share - diluted
|
$ | 0.26 | $ | (0.10 | ) | |||
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 and Brazil are not reportable segments
because the level of activity on these land holdings is not significant at this
time and are 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 income
taxes.
The
results of Colombia and Corporate segments include the operations of Solana
subsequent to the Company’s acquisition of Solana (Note 3) on November 14,
2008.
The
following tables present information on the Company’s reportable geographic
segments:
|
Year Ended December 31,
2009
|
||||||||||||||||
|
(Thousands
of U.S. Dollars except per unit of production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Revenues
|
$ | 248,834 | $ | 13,795 | $ | - | $ | 262,629 | ||||||||
|
Interest
income
|
466 | 127 | 494 | 1,087 | ||||||||||||
|
Depreciation,
depletion & accretion
|
127,213 | 8,339 | 311 | 135,863 | ||||||||||||
|
Depreciation,
depletion & accretion - per unit of production
|
29.64 | 24.72 | - | 29.35 | ||||||||||||
|
Segment
income (loss) before income taxes
|
55,827 | (4,230 | ) | (13,302 | ) | 38,295 | ||||||||||
|
Segment
capital expenditures (1)
|
$ | 81,364 | $ | 4,532 | $ | 2,228 | $ | 88,124 | ||||||||
|
Year Ended December 31,
2008
|
||||||||||||||||
|
(Thousands
of U.S. Dollars except per unit of production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Revenues
|
$ | 103,202 | $ | 9,603 | $ | - | $ | 112,805 | ||||||||
|
Interest
income
|
995 | 23 | 206 | 1,224 | ||||||||||||
|
Depreciation,
depletion & accretion
|
22,199 | 3,390 | 148 | 25,737 | ||||||||||||
|
Depreciation,
depletion & accretion - per unit of production
|
20.41 | 13.95 | - | 19.34 | ||||||||||||
|
Segment
income (loss) before income taxes
|
58,490 | (3,157 | ) | (10,894 | ) | 44,439 | ||||||||||
|
Segment
capital expenditures
|
$ | 31,725 | $ | 11,690 | $ | 3,313 | $ | 46,728 | ||||||||
|
Year Ended December 31,
2007
|
||||||||||||||||
|
(Thousands
of U.S. Dollars except per unit of production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Revenues
|
$ | 23,749 | $ | 8,104 | $ | - | $ | 31,853 | ||||||||
|
Interest
income
|
222 | 15 | 188 | 425 | ||||||||||||
|
Depreciation,
depletion & accretion
|
6,850 | 2,477 | 88 | 9,415 | ||||||||||||
|
Depreciation,
depletion & accretion - per unit of production
|
20.56 | 11.66 | - | 17.26 | ||||||||||||
|
Segment
income (loss) before income taxes
|
11,484 | (2,475 | ) | (17,181 | ) | (8,172 | ) | |||||||||
|
Segment
capital expenditures
|
$ | 14,215 | $ | 1,679 | $ | 731 | $ | 16,625 | ||||||||
76
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
|
As at December 31, 2009
|
||||||||||||||||
|
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Property,
plant & equipment
|
$ | 681,854 | $ | 24,510 | $ | 6,379 | $ | 712,743 | ||||||||
|
Goodwill
|
102,581 | - | - | 102,581 | ||||||||||||
|
Other
assets
|
123,380 | 12,574 | 192,530 | 328,484 | ||||||||||||
|
Total
Assets
|
$ | 907,815 | $ | 37,084 | $ | 198,909 | $ | 1,143,808 | ||||||||
|
As at December 31, 2008
|
||||||||||||||||
|
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Property,
plant & equipment
|
$ | 735,208 | $ | 27,882 | $ | 4,462 | $ | 767,552 | ||||||||
|
Goodwill
|
98,582 | - | - | 98,582 | ||||||||||||
|
Other
assets
|
44,554 | 8,868 | 153,069 | 206,491 | ||||||||||||
|
Total
Assets
|
$ | 878,344 | $ | 36,750 | $ | 157,531 | $ | 1,072,625 | ||||||||
(1) Net
of net proceeds from the disposition of the Guachiria Blocks (see Note
5).
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 2009, the Company had one significant customer for its Colombian
crude oil, Ecopetrol S.A. (“Ecopetrol”), a Colombian government agency. Sales to
Ecopterol accounted for 94% of the Company’s revenues in 2009, 89% in 2008, and
75% in 2007. In Argentina, the Company had one significant customer, Refineria
del Norte S.A. (“Refiner”). Sales to Refiner accounted for 6% of the Company’s
revenues in 2009, 9% in 2008, and 25% in 2007.
5.
Property, Plant and
Equipment
|
As
at
December
31,
2009
|
As
at
December
31,
2008
|
|||||||||||||||||||||||
|
(Thousands of U.S. Dollars)
|
Cost
|
Accumulated
DD&A
|
Net
book
value
|
Cost
|
Accumulated
DD&A
|
Net
book
value
|
||||||||||||||||||
|
Oil
and natural gas properties
|
||||||||||||||||||||||||
|
Proved
|
$ | 648,061 | $ | (173,382 | ) | $ | 474,679 | $ | 419,539 | $ | (38,684 | ) | $ | 380,855 | ||||||||||
|
Unproved
|
234,889 | - | 234,889 | 384,195 | - | 384,195 | ||||||||||||||||||
| 882,950 | (173,382 | ) | 709,568 | 803,734 | (38,684 | ) | 765,050 | |||||||||||||||||
|
Furniture
and fixtures and leasehold improvements
|
3,843 | (2,185 | ) | 1,658 | 1,979 | (848 | ) | 1,131 | ||||||||||||||||
|
Computer
equipment
|
3,148 | (1,907 | ) | 1,241 | 1,791 | (526 | ) | 1,265 | ||||||||||||||||
|
Automobiles
|
513 | (237 | ) | 276 | 163 | (57 | ) | 106 | ||||||||||||||||
|
Total
Property, Plant and Equipment
|
$ | 890,454 | $ | (177,711 | ) | $ | 712,743 | $ | 807,667 | $ | (40,115 | ) | $ | 767,552 | ||||||||||
77
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
DD&A
for 2009 included a $1.9 million ceiling test impairment loss in our Argentina
cost center. This impairment loss resulted from higher forecasted operating
costs to produce remaining proved reserves.
The
Company capitalized $1.6 million (2008 - $1.9 million; 2007 - $1.7 million) of
general and administrative expenses related to the Colombian full cost center,
including $0.2 million (2008 - $0.4 million; 2007 - $0.1 million) of stock based
compensation expense, and $0.6 million (2008 - $0.8 million; 2007 - $0.2
million) of general and administrative expenses in the Argentina full cost
center, including $0.1 million (2008 - $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 had $229.1 million (December 31, 2008
- $375.9 million) in unproved assets in Colombia, $0.4 million (December 31,
2008 - $4.7 million) of unproved assets in Argentina and $5.4 million (December
31, 2008 - $3.6 million) of unproved assets in Peru. These properties are being
held for their exploration value and are not being depleted pending
determination of the existence of proved reserves. Gran Tierra will continue to
assess 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.
In April
2009, Gran Tierra closed the sale of the Company’s interests in the Guachiria
Norte, Guachiria, and Guachiria Sur blocks in Colombia. Principal terms included
consideration of $7.0 million comprising an initial cash payment of $4.0 million
at closing, followed by 15 monthly installments of $200,000 each which began on
June 1, 2009 and extending through August 3, 2010. The Company recorded net
proceeds of $6.3 million. Gran Tierra retained a 10% overriding royalty interest
on the Guachiria Sur block, which, in the event of a discovery, is designed to
reimburse 200% of the Company’s costs for previously acquired seismic
data.
The
following is a summary of Gran Tierra’s oil and natural gas properties not
subject to depletion as at December 31, 2009:
|
Costs Incurred in
|
||||||||||||||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008
|
2007
|
2006
|
Total
|
|||||||||||||||
|
Acquisition
costs - Colombia
|
$ | - | $ | 206,106 | $ | - | $ | 6,282 | $ | 212,388 | ||||||||||
|
Exploration
costs - Argentina
|
163 | 229 | - | - | 392 | |||||||||||||||
|
Exploration
costs - Colombia
|
6,598 | 3,213 | 806 | - | 10,617 | |||||||||||||||
|
Exploration
costs - Peru
|
1,969 | 2,767 | 656 | - | 5,392 | |||||||||||||||
|
Development
costs - Colombia
|
6,100 | - | - | - | 6,100 | |||||||||||||||
|
Total
oil and natural gas properties not subject to depletion
|
$ | 14,830 | $ | 212,315 | $ | 1,462 | $ | 6,282 | $ | 234,889 | ||||||||||
6.
Share
Capital
The
Company’s authorized share capital consists of 595,000,002 shares of capital
stock, of which 570 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 are designated as special voting
stock, par value $0.001 per share. On June 16, 2009, the shareholders of Gran
Tierra approved an amendment to the Articles of Incorporation to increase the
authorized number of shares of common stock from 300,000,000 to 570,000,000
shares. As at December 31, 2009, outstanding share capital consists of
219,459,361 common voting shares of the Company, 14,306,973 exchangeable shares
of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013,
and 10,332,540 exchangeable shares of Goldstrike Exchange Co., automatically
exchangeable on November 10, 2010. The exchangeable shares of Gran Tierra
Exchange Co, were issued upon acquisition of Solana. The exchangeable shares of
Gran Tierra Goldstrike Inc. were issued upon the business combination between
Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is
now the Company. Each exchangeable share is exchangeable 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 Company’s 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.
78
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Warrants
At
December 31, 2009, the Company has 5,221,862 warrants outstanding to purchase
2,610,931 common shares for $1.25 per share, expiring between September 1, 2010
and February 2, 2011, 10,561,180 warrants outstanding to purchase 5,280,590
common shares for $1.05 per share, expiring between June 20, 2012 and June 30,
2012, and 7,145,938 warrants assumed upon the acquisition of Solana to purchase
7,145,938 common shares for CDN$2.10 per share, expiring April 2, 2010. For the
year ended December 31, 2009, 4,221,193 common shares were issued upon the
exercise of 10,913,660 warrants (year ended December 31, 2008, 20,479,546 common
shares were issued upon the exercise of 41,138,370 warrants; year ended December
31, 2007, 670,067 common shares were issued upon the exercise of 1,340,134
warrants).
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 -
Restatement
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 with a term of five years. As a result of the 2006
Offering, 50 million shares of Gran Tierra’s common stock were issued. 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 file a registration statement with the SEC permitting the
public resale of the shares and warrants (and shares issuable upon exercise of
the warrants) issued to the investors in the 2006 Offering by November 17, 2007
and failure to do so would result in liquidated damages. The registration
statement filed by Gran Tierra with the SEC to satisfy its obligations under the
Registration Rights Agreements was declared effective by the SEC on May 14,
2007. As a result, Gran Tierra had accrued $8.6 million in liquidated damages
under the Registration Rights Agreements. The $8.6 million of liquidated damages
was 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.
On June
27, 2007, pursuant to the terms of the Registration Rights Agreements, the
Company obtained a sufficient number of consents from the signatories to the
Registration Rights Agreements waiving Gran Tierra’s obligation to pay in cash
the accrued liquidated damages. In exchange for amending the Registration Rights
Agreements whereby the holders waived their rights to a cash payment, 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. The revised fair value of the warrants was determined
by Gran Tierra using a Black-Scholes option pricing model using inputs similar
to those used for the Company’s stock based compensation awards except that,
instead of an historical volatility rate, Gran Tierra used a 25% volatility
rate, which Gran Tierra believed at the time reflected a typical volatility rate
used to value this type of financial instrument and resulted in the fair value
of the modified warrants being equivalent to the amount of the liquidated
damages ultimately waived by the parties to the Registration Rights Agreements.
As a result, $8.6 million was credited to warrants on the consolidated balance
sheet.
The
Company had previously reported this fair value of the modified warrants in its
audited financial statements for the fiscal years ended December 31, 2007 and
December 31, 2008 and its unaudited financial statements for the quarters ended
March 31, 2009, June 30, 2009, and September 30, 2009.
In the
fourth quarter of 2009, the Company determined that the previously disclosed
basis for determining the valuation of the warrant modification was inconsistent
with the inputs used in the Black-Scholes option pricing model to determine the
fair value of the Company’s stock based compensation awards. As a result, Gran
Tierra determined in 2009 to change its methodology which resulted in the fair
value of the Company’s modified warrants (using the Black-Scholes option pricing
model utilized by the Company for its stock based compensation
awards) equaling
$4.2 million (rather than $8.6 million). As a result, $4.4 million (the excess
of the liquidated damages settled and the fair value of the amendment to the
warrants) has been restated as a decrease in warrants with a corresponding
increase in additional paid-in capital as at June 27, 2007. The Company has
recorded this excess as an equity transaction as it relates to the
extinguishment of debt with a related party since the parties to the
Registration Rights Agreements comprised over 50 percent of the outstanding
shareholdings of the Company at the time of the transaction involving the
amendment of the Registration Rights Agreements (which agreements provided that
amendments to the Registrations Rights Agreements would be decided by a majority
of the then outstanding registrable shares, as defined in the
agreements).
79
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
The
inputs used in the Black-Scholes option pricing model to determine the change in
the fair value of the modified warrants contemplated by the amendment to the
Registration Rights Agreements are as follows:
|
Immediately Before
Modification
|
Immediately
Subsequent to
Modification
|
|||||||
|
Common
share price (closing price June 26, 2007)
|
$ | 1.33 | $ | 1.33 | ||||
|
Exercise
price
|
$ | 1.75 | $ | 1.05 | ||||
|
Dividend
yield (per share)
|
$ | nil | $ | nil | ||||
|
Volatility
|
100% | 100% | ||||||
|
Risk-free
interest rate
|
4.69% | 4.67% | ||||||
|
Expected
term
|
4
years
|
5
years
|
||||||
|
Estimated
forfeiture percentage (per year)
|
0% | 0% | ||||||
Stock Options
As at
December 31, 2009, 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 increased the number of shares
of common stock available for issuance thereunder from 9,000,000 shares to
18,000,000 shares.
The
Company grants 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.
For the year ended December 31, 2009, 1,391,028 common shares were issued upon
the exercise of 1,391,028 stock options (year ended December 31, 2008 –
209,164; year ended December 31, 2007 - nil). The following options are
outstanding as of December 31, 2009:
|
Number of
|
Weighted Average
|
Number of
|
Weighted Average
|
|||||||||||||
|
Outstanding
|
Exercise Price
|
Nonvested
|
Grant-Date Fair Value
|
|||||||||||||
|
Options
|
$/Option
|
Options
|
$/Option
|
|||||||||||||
|
Balance,
December 31, 2008
|
11,406,870 | $ | 2.13 | 8,093,351 | $ | 1.45 | ||||||||||
|
Granted
in 2009
|
1,525,000 | 4.09 | 1,525,000 | 2.43 | ||||||||||||
|
Exercised
in 2009
|
(1,391,028 | ) | (1.64 | ) | - | - | ||||||||||
|
Vested
in 2009
|
- | - | (3,397,471 | ) | 1.38 | |||||||||||
|
Forfeited
in 2009
|
(452,226 | ) | (2.91 | ) | (261,668 | ) | 1.49 | |||||||||
|
Balance,
December 31, 2009
|
11,088,616 | $ | 2.43 | 5,959,212 | $ | 1.74 | ||||||||||
The
weighted average grant date fair value for options granted in 2009 was $2.43
(2008 - $1.55; 2007 - $1.10). The intrinsic value of options exercised in 2009
was $2.9 million (2008 - $0.8 million; 2007 - nil). The total fair value of
shares vested during 2009 was $4.7 million.
The table
below summarizes stock options outstanding at December 31, 2009:
|
Number of
|
Weighted Average
|
Weighted
|
||||||||||
|
Outstanding
|
Exercise Price
|
Average
|
||||||||||
|
Range of Exercise Prices ($/option)
|
Options
|
$/Option
|
Expiry Years
|
|||||||||
|
0.50
to 1.30
|
2,197,337 | $ | 1.07 | 6.5 | ||||||||
|
1.31
to 2.00
|
320,974 | 1.75 | 7.1 | |||||||||
|
2.01
to 3.50
|
7,490,305 | 2.44 | 8.7 | |||||||||
|
3.51
to 5.50
|
585,000 | 4.42 | 9.7 | |||||||||
|
5.51
to 7.75
|
495,000 | 6.30 | 9.6 | |||||||||
|
Total
|
11,088,616 | $ | 2.43 | 8.3 | ||||||||
80
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
The
aggregate intrinsic value of options outstanding at December 31, 2009 is $39.0
million (2008 - $8.9 million) based on the Company’s closing stock price of
$5.73 (2008 - $2.80) for that date. At December 31, 2009, there was $5.4 million
(2008 - $7.9 million) of unrecognized compensation cost related to unvested
stock options which is expected to be recognized over the next three
years.
The table
below summarizes exercisable stock options at December 31, 2009:
|
Range of Exercise Prices
($/option)
|
Number of Exercisable
Options
|
Weighted Average Exercise
Price $/Option
|
Weighted Average
Expiry Years
|
|||||||||
|
0.50
to 1.30
|
1,939,003 | $ | 1.05 | 6.4 | ||||||||
|
1.31
to 2.00
|
192,638 | $ | 1.77 | 6.7 | ||||||||
|
2.01
to 3.50
|
2,949,431 | $ | 2.38 | 8.5 | ||||||||
|
5.51
to 7.75
|
33,333 | $ | 7.75 | 8.5 | ||||||||
|
Total
|
5,114,405 | $ | 1.89 | 7.7 | ||||||||
The
weighted average grant date fair value for options vested in 2009 was $1.38
(2008 - $1.17). The aggregate intrinsic value of options exercisable
at December 31, 2009 is $19.8 million (2008 - $4.8 million) based on the
Company’s closing stock price of $5.73 for that date.
In 2009,
the stock based compensation expense was $5.6 million (2008 - $3.1 million; 2007
- $1.0 million) of which $4.5 million (2008 - $2.3 million; 2007 - $0.7 million)
was recorded in general and administrative expense and $0.8 million (2008 - $0.2
million; 2007 - $0.1 million) was recorded in operating expense in the
consolidated statement of operations. In 2009, $0.3 million (2008 - $0.6
million; 2007 - $0.2 million) of stock based compensation 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.
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Dividend
yield (per share)
|
$ | nil | $ | nil | $ | nil | ||||||
|
Volatility
|
94%
to 98%
|
75%
to 103%
|
94%
to 103%
|
|||||||||
|
Risk-free
interest rate
|
0.4% to 0.6%
|
1.1% to 2.1%
|
3.5% to 5.6%
|
|||||||||
|
Expected
term
|
3
years
|
3
years
|
3
years
|
|||||||||
|
Estimated
forfeiture percentage (per year)
|
10% | 10% | 10% | |||||||||
Weighted average shares outstanding
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Weighted
average number of common and exchangeable shares
outstanding
|
241,258,568 | 123,421,898 | 95,096,311 | |||||||||
|
Shares
issuable pursuant to warrants
|
9,503,818 | 14,663,885 | - | |||||||||
|
Shares
issuable pursuant to stock options
|
5,797,322 | 6,020,738 | - | |||||||||
|
Shares
to be purchased from proceeds of stock options
|
(2,969,605 | ) | (911,931 | ) | - | |||||||
|
Weighted
average number of diluted common and exchangeable shares
outstanding
|
253,590,103 | 143,194,590 | 95,096,311 | |||||||||
81
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Income (loss) per share
At
December 31, 2009, 2008 and 2007, 1,080,000, 100,000 and 5,724,168 options
to purchase common shares and warrants to purchase nil, nil and 33,917,536
common shares, respectively, were excluded from the diluted loss per share
calculation as the instruments were anti-dilutive.
7
.
Asset Retirement
Obligation
As
at December 31, 2009 the Company’s asset retirement obligation was
comprised of a Colombian obligation in the amount of $3.5 million (December 31,
2008 - $3.5 million) and an Argentine obligation in the amount of $1.2 million
(December 31, 2008 - $0.8 million). The undiscounted asset retirement obligation
is $7.7 million. Changes in the carrying amounts of the asset retirement
obligations associated with the Company’s oil and natural gas properties were as
follows:
|
As at December 31,
|
||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008
|
||||||
|
Balance,
beginning of year
|
$ | 4,251 | $ | 799 | ||||
|
Liability
assumed in a business combination (Note 3)
|
- | 3,148 | ||||||
|
Settlements
|
(52 | ) | (334 | ) | ||||
|
Disposal
|
(734 | ) | - | |||||
|
Liability
incurred
|
921 | 615 | ||||||
|
Foreign
exchange
|
24 | (29 | ) | |||||
|
Accretion
|
298 | 52 | ||||||
|
Balance,
end of year
|
$ | 4,708 | $ | 4,251 | ||||
|
Asset
retirement obligation - current
|
$ | 450 | $ | - | ||||
|
Asset
retirement obligation - long term
|
4,258 | 4,251 | ||||||
|
Balance,
end of year
|
$ | 4,708 | $ | 4,251 | ||||
8.
Income
Taxes
The
income tax expense reported differs from the amount computed by applying the US
statutory rate to income (loss) before income taxes for the following
reasons:
82
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
|
Year Ended December 31,
|
||||||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008 (1)
|
2007 (1)
|
|||||||||
|
Income
(loss) before income taxes
|
$ | 38,295 | $ | 44,439 | (8,172 | ) | ||||||
| 35.00 | % | 35.00 | % | 35.00 | % | |||||||
|
Income
tax expense (benefit) expected
|
13,403 | 15,554 | (2,860 | ) | ||||||||
|
Permanent
differences
|
1,594 | 2,723 | (377 | ) | ||||||||
|
Foreign
currency translation adjustments
|
1,099 | 4,636 | 5,058 | |||||||||
|
Impact
of foreign taxes
|
(1,565 | ) | (1,337 | ) | (43 | ) | ||||||
|
Enhanced
tax depreciation incentive
|
(3,380 | ) | (4,560 | ) | (1,597 | ) | ||||||
|
Stock
based compensation
|
1,814 | 707 | 223 | |||||||||
|
Increase
(decrease) in valuation allowance
|
16,199 | 8,537 | (4,167 | ) | ||||||||
|
Partnership
and branch income (loss) pick-up in the United States and
Canada
|
(5,931 | ) | 21,673 | 4,058 | ||||||||
|
Utilization
of foreign tax credits
|
71 | (26,989 | ) | - | ||||||||
|
Other
|
1,050 | - | - | |||||||||
|
Total
income tax expense
|
$ | 24,354 | $ | 20,944 | $ | 295 | ||||||
|
Current
income tax
|
38,795 | 25,256 | 2,800 | |||||||||
|
Deferred
tax recovery
|
(14,441 | ) | (4,312 | ) | (2,505 | ) | ||||||
|
Total
income tax expense
|
$ | 24,354 | $ | 20,944 | $ | 295 | ||||||
|
As at December 31,
|
||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008
|
||||||
|
Deferred
Tax Assets
|
||||||||
|
Tax
benefit of loss carryforwards
|
$ | 22,318 | $ | 16,905 | ||||
|
Book
value in excess of tax basis
|
1,691 | 1,228 | ||||||
|
Foreign
tax credits and other accruals
|
15,508 | 9,595 | ||||||
|
Capital
losses
|
1,481 | 1,419 | ||||||
|
Deferred
tax assets before valuation allowance
|
40,998 | 29,147 | ||||||
|
Valuation
allowance
|
(29,528 | ) | (16,754 | ) | ||||
| $ | 11,470 | $ | 12,393 | |||||
|
Deferred
tax assets - current
|
$ | 4,252 | $ | 2,262 | ||||
|
Deferred
tax assets - long-term
|
7,218 | 10,131 | ||||||
| 11,470 | 12,393 | |||||||
|
Deferred
Tax Liabilities
|
||||||||
|
Current
- book value in excess of tax basis
|
- | (100 | ) | |||||
|
Long-term
- book value in excess of tax basis
|
(216,625 | ) | (213,093 | ) | ||||
| (216,625 | ) | (213,193 | ) | |||||
|
Net
Deferred Tax Liabilities
|
$ | (205,155 | ) | $ | (200,800 | ) | ||
|
(1)
|
For
the year ended December 31, 2009, the Company has used the United States
statutory tax rate of 35% in the reconciliation of income taxes.
Previously, the Company used the Canadian statutory rate in the
reconciliation. This change was determined on the basis that Gran Tierra
is a United States resident corporation and a reconciliation beginning
with the United States statutory tax rate is more informative. The 2008
and 2007 comparative income tax reconciliations have been recomputed using
the United States statutory rate. This change in presentation has no
impact on the income tax amounts reported in the consolidated statements
of operations for the years ended December 31, 2008 and 2007,
respectively.
|
83
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. 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 in the Company’s financial statements as of December 31, 2009
was $0.9 million (December 31, 2008 - $1.1 million).
On
January 1, 2007, the Company adopted the provisions of ASC 740,
Income Taxes
, however, there
was no impact on the opening accumulated deficit of the Company as a result of
this adoption. The Company and its subsidiaries file income tax
returns in the U.S. federal and state jurisdictions and certain other foreign
jurisdictions. The Company is subject to income tax examinations for the
calendar tax years ended 2005 through 2009 in most jurisdictions.
As at
December 31, 2009, the Company has deferred tax assets relating to net operating
loss carryforwards of $22.3 million (December 31, 2008 - $17.0 million) and
capital losses of $1.5 million (December 31, 2008 – $1.4 million) before
valuation allowances. Of these losses, $18.2 million (December 31, 2008 - $17.0
million) are losses generated by the foreign subsidiaries of the Company. Of the
total losses $0.1 million (December 31, 2008 - $1.4 million) will begin to
expire by 2011 and $23.7 million of net operating losses (December 31, 2008 -
$17.0 million) will begin to expire thereafter.
9.
Accounts Payable and Accrued
Liabilities
The
balances in accounts payable and accrued liabilities are comprised of the
following:
|
As at December 31, 2009
|
||||||||||||||||
|
(Thousands of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Property,
plant and equipment
|
$ | 17,723 | $ | 844 | $ | 213 | $ | 18,780 | ||||||||
|
Payroll
|
1,792 | 339 | 1,052 | 3,183 | ||||||||||||
|
Audit,
legal, consultants
|
- | 137 | 1,472 | 1,609 | ||||||||||||
|
General
and administrative
|
2,542 | 284 | 213 | 3,039 | ||||||||||||
|
Operating
|
48,756 | 1,648 | - | 50,404 | ||||||||||||
|
Total
|
$ | 70,813 | $ | 3,252 | $ | 2,950 | $ | 77,015 | ||||||||
|
As at December 31, 2008
|
||||||||||||||||
|
(Thousands of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
|
Property,
plant and equipment
|
$ | 11,654 | $ | 1,254 | $ | 4 | $ | 12,912 | ||||||||
|
Payroll
|
978 | 435 | 921 | 2,334 | ||||||||||||
|
Audit,
legal, consultants
|
- | 126 | 1,351 | 1,477 | ||||||||||||
|
General
and administrative
|
1,193 | 52 | 898 | 2,143 | ||||||||||||
|
Operating
|
13,309 | 1,800 | - | 15,109 | ||||||||||||
|
Total
|
$ | 27,134 | $ | 3,667 | $ | 3,174 | $ | 33,975 | ||||||||
10. Commitments and
Contingencies
Leases
Gran
Tierra holds three categories of operating leases: office, vehicle and housing.
The Company pays monthly amounts of $163,167 for office leases, $14,095 for
vehicle leases and $6,815 for certain employee accommodation leases in Colombia,
Argentina and Peru. Future lease payments at December 31, 2009 are as
follows:
84
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
|
As at December 31, 2009
|
||||||||||||||||||||
|
Payments Due in Period
|
||||||||||||||||||||
|
Contractual Obligations
|
Total
|
Less than 1
Year
|
1 to 3
years
|
3 to 5
years
|
More than
5 years
|
|||||||||||||||
|
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||
|
Operating
leases
|
$ | 6,464 | $ | 2,047 | $ | 3,086 | $ | 1,331 | $ | - | ||||||||||
|
Software
and Telecommunication
|
1,835 | 1,209 | 626 | - | - | |||||||||||||||
|
Drilling,
Completion, Facility Construction and Oil Transportation
Services
|
24,985 | 24,882 | 103 | - | - | |||||||||||||||
|
Total
|
$ | 33,284 | $ | 28,138 | $ | 3,815 | $ | 1,331 | $ | - | ||||||||||
Total
rent expense for 2009 was $2.1 million (2008 - $0.9 million; 2007 - $0.3
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. The maximum amount of any potential future
payment cannot be reasonably estimated.
The
Company may provide indemnifications in the normal course of business that are
often standard contractual terms to counterparties in certain transactions such
as purchase and sale agreements. The terms of these indemnifications will vary
based upon the contract, the nature of which prevents the Company from making a
reasonable estimate of the maximum potential amounts that may be required to be
paid. Management believes the resolution of these matters would not have a
material adverse impact on the Company’s liquidity, consolidated financial
position or results of operations.
Contingencies
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
Bogotá. 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 $5.1 million. To the
Company’s knowledge, there are no other legal proceedings against Gran
Tierra.
Gran
Tierra has several lawsuits and claims pending for which the Company currently
cannot determine the ultimate result. Gran Tierra records costs as they are
incurred or become determinable. Gran Tierra believes the resolution of these
matters would not have a material adverse effect on the Company’s consolidated
financial position or results of operations.
11.
Financial Instruments, Fair Value Measurements and Credit
Risk
The
Company’s financial instruments recognized in the balance sheet consist of cash
and cash equivalents, restricted cash, 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. As at
December 31, 2009, 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.
85
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
Additionally,
foreign exchange gains/losses result from the fluctuation of the U.S. dollar to
the Colombian peso due to Gran Tierra’s deferred tax liability, a monetary
liability, which is mainly denominated in the local currency of the
Colombian foreign operations. As a result, a foreign exchange gain/loss
must be calculated on conversion to the US dollar functional currency. A
strengthening in the Colombian peso against the U.S. dollar results in foreign
exchange losses, estimated at $99,000 for each one peso decrease in the exchange
rate of the Colombian peso to one U.S. dollar.
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 2009, the Company had one significant customer for its Colombian
crude oil, Ecopetrol S.A., a Colombian government agency. In Argentina, the
Company had 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.
|
Year Ended December 31,
|
||||||||||||
|
(Thousands of U.S. Dollars)
|
2009
|
2008
|
2007
|
|||||||||
|
Realized
financial derivative (gain) loss
|
$ | (87 | ) | $ | 2,689 | $ | 391 | |||||
|
Unrealized
financial derivative (gain) loss
|
277 | (2,882 | ) | 2,649 | ||||||||
|
Derivative
financial instruments (gain) loss
|
$ | 190 | $ | (193 | ) | $ | 3,040 | |||||
|
As at December 31,
|
||||||||||||
|
Assets
(Liabilities)
|
2009
|
2008
|
||||||||||
|
Derivative
financial instruments
|
$ | (44 | ) | $ | 233 | |||||||
Certain
of Gran Tierra’s assets and liabilities are reported at fair value in the
accompanying consolidated balance sheets. The following tables provide fair
value measurement information for such assets and liabilities as at December 31,
2009 and December 31, 2008.
The
carrying values of cash and cash equivalents, restricted cash, accounts
receivable and accounts payable (including accrued liabilities) included in the
accompanying consolidated balance sheets approximated fair value at December 31,
2009 and December 31, 2008. These assets and liabilities are not presented in
the following tables.
86
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
|
As at December 31, 2009
|
||||||||||||||||||||
|
Fair Value Measurements Using:
|
||||||||||||||||||||
|
Quoted
|
Significant
|
|||||||||||||||||||
|
Prices in
|
Other
|
Significant
|
||||||||||||||||||
|
Active
|
Observable
|
Unobservable
|
||||||||||||||||||
|
Carrying
|
Total Fair
|
Markets
|
Inputs
|
Inputs
|
||||||||||||||||
|
Amount
|
Value
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||||||
|
Financial Liabilities
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Crude
oil collar
|
$ | (44 | ) | $ | (44 | ) | $ | - | $ | (44 | ) | $ | - | |||||||
|
As at December 31, 2008
|
||||||||||||||||||||
|
Fair Value Measurements Using:
|
||||||||||||||||||||
|
Quoted
|
Significant
|
|||||||||||||||||||
|
Prices in
|
Other
|
Significant
|
||||||||||||||||||
|
Active
|
Observable
|
Unobservable
|
||||||||||||||||||
|
Carrying
|
Total Fair
|
Markets
|
Inputs
|
Inputs
|
||||||||||||||||
|
Amount
|
Value
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||||||
|
Financial Assets
(Thousands of U.S. Dollars)
|
||||||||||||||||||||
|
Crude
oil collar
|
$ | 233 | $ | 233 | $ | - | $ | 233 | $ | - | ||||||||||
GAAP
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 a 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,
non-binding quotes obtained from brokers for contracts with similar terms which
can be substantially observed or corroborated in the marketplace, or quotes
obtained from counterparties to the agreements. The Company does not have any
other assets or liabilities whose fair value is measured using Level 1 or 3
methods.
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 collars are estimated using internal discounted cash
flow calculations based upon forward commodity price curves, non-binding quotes
obtained from brokers for contracts with similar terms which can be
substantially observed or corroborated in the marketplace, 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.
87
Gran
Tierra Energy Inc.
Notes
to the Consolidated Financial Statements
For
the Years Ended December 31, 2009, 2008 and 2007
Expressed
in U.S. Dollars, unless otherwise stated
12.
Credit Facilities
Effective
February 28, 2007, the Company entered into a credit facility with Standard Bank
Plc. As a result of re-negotiations concluded in August 2009, the maximum amount
of the credit facility was $200 million with a $7 million borrowing base that
could be re-determined semi-annually based on reserve evaluation reports. As a
result of Standard Bank Plc’s review of Gran Tierra’s 2008 Independent Reserve
Audit, the Company had the capacity to increase the borrowing base to $120
million under the revised facility; however, this was not pursued further as the
additional borrowing base was not required. The facility included a letter of
credit sub-limit of $5 million. Amounts drawn down under the facility bore
interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum was
charged on the un-drawn amount of the borrowing base. The facility was secured
primarily by the assets of Gran Tierra Colombia and Solana Petroleum Exploration
(Colombia) Ltd. Under the terms of the facility, the Company was required to
maintain and was in 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 June 30, 2006 Independent Reserve Evaluation Report
projected aggregate net share of Colombian production after royalties for the
three-year term of the Facility. As at December 31, 2009, no amount was
drawn-down under this facility. This facility expired February 22,
2010.
Following
the acquisition of Solana, effective November 14, 2008, Gran Tierra obtained
access to an additional credit facility with BNP Paribas. The facility had a
maturity date of December 20, 2010. The borrowing base was $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. This facility was
cancelled effective August 4, 2009.
As of
February 26
,
2010
the Company is negotiating a facility with a major bank to
replace the expired Standard Bank facility. The Company intends for this
facility to be in place by the second quarter of
2010.
13.
Related Party Transaction
On
February 1, 2009, the Company entered into a sublease for 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 $7,800 per month plus approximately $4,000 for operating and
other expenses. The terms of the sublease were consistent with market conditions
in the Calgary, Alberta, Canada real estate market.
14.
Subsequent Event
On
January 20, 2010, the Company issued 3,572,969 common shares upon the exercise
of 3,572,969 warrants issued upon the acquisition of Solana for $7.1 million or
$2.01 per share.
88
Supplementary
Data (Unaudited)
1)
Oil and Gas Producing Activities
The
following oil and gas information is provided in accordance with ASC 932,
“Extractive Activities – Oil and Gas
”
.
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 disclosure included
in the following supplementary financial information conforms to the new
requirements as disclosed in Note 2 of the December 31, 2009 consolidated
financial statements.
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.
89
PROVED
RESERVES NET OF ROYALTIES (1)
|
Crude oil is in
barrels and
|
Colombia
|
Argentina
|
Total
|
|||||||||||||||||||||
|
natural
gas
is
in
million
cubic
feet
|
Oil
|
Gas
|
Oil
|
Gas
|
Oil
|
Gas
|
||||||||||||||||||
|
Proved
Developed and Undeveloped Reserves, December 31,
2006
|
1,095,000 | - | 1,895,000 | 1,465 | 2,990,000 | 1,465 | ||||||||||||||||||
|
Extensions
and Discoveries
|
3,477,000 | - | - | - | 3,477,000 | - | ||||||||||||||||||
|
Purchases
of Reserves in Place
|
- | - | - | - | - | - | ||||||||||||||||||
|
Production
|
(333,157 | ) | - | (207,912 | ) | (27 | ) | (541,069 | ) | (27 | ) | |||||||||||||
|
Revisions
of Previous Estimates
|
144,157 | - | 347,912 | (1,438 | ) | 492,069 | (1,438 | ) | ||||||||||||||||
|
Proved
Developed and Undeveloped Reserves, December 31,
2007
|
4,383,000 | - | 2,035,000 | - | 6,418,000 | - | ||||||||||||||||||
|
Extensions
and Discoveries
|
5,344,202 | - | 377,300 | - | 5,721,502 | - | ||||||||||||||||||
|
Purchases
of Reserves in Place
|
9,016,148 | 1,179 | - | - | 9,016,148 | 1,179 | ||||||||||||||||||
|
Production
|
(1,085,198 | ) | (15 | ) | (242,947 | ) | - | (1,328,145 | ) | (15 | ) | |||||||||||||
|
Revisions
of Previous Estimates
|
22,848 | (2 | ) | (612,353 | ) | - | (589,505 | ) | (2 | ) | ||||||||||||||
|
Proved
Developed and Undeveloped reserves, December 31, 2008
|
17,681,000 | 1,162 | 1,557,000 | - | 19,238,000 | 1,162 | ||||||||||||||||||
|
Extensions
and Discoveries
|
2,025,000 | - | - | - | 2,025,000 | - | ||||||||||||||||||
|
Purchases
of Reserves in Place
|
(113,000 | ) | - | - | - | (113,000 | ) | - | ||||||||||||||||
|
Production
|
(4,284,230 | ) | (49 | ) | (337,316 | ) | - | (4,621,546 | ) | (49 | ) | |||||||||||||
|
Revisions
of Previous Estimates
|
5,482,230 | - | 71,316 | 756 | 5,553,546 | 756 | ||||||||||||||||||
|
Proved
Developed and Undeveloped Reserves, December 31, 2009
|
20,791,000 | 1,113 | 1,291,000 | 756 | 22,082,000 | 1,869 | ||||||||||||||||||
|
Proved
Developed Reserves, December 31, 2007 (2)
|
3,444,000 | - | 1,819,000 | - | 5,263,000 | - | ||||||||||||||||||
|
Proved
Developed Reserves, December 31, 2008 (2)
|
7,832,000 | - | 1,134,000 | - | 8,966,000 | - | ||||||||||||||||||
|
Proved
Developed Reserves, December 31, 2009 (2)
|
20,194,000 | 1,113 | 1,080,000 | 756 | 21,274,000 | 1,869 | ||||||||||||||||||
90
|
(1)
|
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.
|
|
(2)
|
Proved
developed oil and gas reserves are expected to be recovered through
existing wells with existing equipment and operating
methods.
|
B.
Capitalized Costs
|
Proved
|
Unproved
|
Accumulated
|
Capitalized
|
|||||||||||||
|
Properties
|
Properties
|
DD&A
|
Costs
|
|||||||||||||
|
Capitalized
Costs, December 31, 2008
|
$ | 419,664 | $ | 380,592 | $ | (38,809 | ) | $ | 761,447 | |||||||
|
Colombia
|
219,128 | (146,793 | ) | (126,261 | ) | (53,926 | ) | |||||||||
|
Argentina
|
9,269 | (4,302 | ) | (8,312 | ) | (3,345 | ) | |||||||||
|
Capitalized
Costs, December 31, 2009
|
$ | 648,061 | $ | 229,497 | $ | (173,382 | ) | $ | 704,176 | |||||||
C.
Costs Incurred
|
Oil and Gas
|
||||||||||||
|
|
Colombia
|
Argentina
|
Total
|
|||||||||
|
Total
Costs
Incurred
before
DD&A
|
||||||||||||
|
Property
Acquisition Costs
|
||||||||||||
|
Proved
|
$ | - | $ | - | $ | - | ||||||
|
Unproved
|
- | - | - | |||||||||
|
Exploration
Costs
|
10,075 | - | 10,075 | |||||||||
|
Development
Costs
|
4,070 | 1,633 | 5,703 | |||||||||
|
As
at December 31, 2007
|
$ | 52,726 | $ | 23,360 | $ | 76,086 | ||||||
|
Property
Acquisition Costs
|
||||||||||||
|
Proved
|
$ | 320,773 | $ | - | $ | 320,773 | ||||||
|
Unproved
|
360,493 | - | 360,493 | |||||||||
|
Exploration
Costs
|
3,443 | 7,990 | 11,433 | |||||||||
|
Development
Costs
|
27,597 | 3,874 | 31,471 | |||||||||
|
As
at December 31, 2008
|
$ | 765,032 | $ | 35,224 | $ | 800,256 | ||||||
|
Property
Acquisition Costs
|
||||||||||||
|
Proved
|
$ | - | $ | - | $ | - | ||||||
|
Unproved
|
- | - | - | |||||||||
|
Exploration
Costs
|
24,103 | 246 | 24,349 | |||||||||
|
Development
Costs
|
48,232 | 4,721 | 52,953 | |||||||||
|
As
at December 31, 2009
|
$ | 837,367 | $ | 40,191 | $ | 877,558 | ||||||
91
D.
Results of Operations for Producing Activities
|
|
Colombia
|
Argentina
|
Total
|
|||||||||
|
Year ended December 31,
2007
|
||||||||||||
|
Net
Sales
|
$ | 23,749 | $ | 8,104 | $ | 31,853 | ||||||
|
Production
Costs
|
(4,097 | ) | (6,327 | ) | (10,424 | ) | ||||||
|
Exploration
Expense
|
- | - | - | |||||||||
|
DD&A
|
(6,850 | ) | (2,477 | ) | (9,327 | ) | ||||||
|
Income
Tax (Expense) Recovery
|
(1,354 | ) | 1,065 | (289 | ) | |||||||
|
Results of
Operations
|
$ | 11,448 | $ | 365 | $ | 11,813 | ||||||
|
Year ended December 31,
2008
|
||||||||||||
|
Net
Sales
|
$ | 103,202 | $ | 9,603 | $ | 112,805 | ||||||
|
Production
Costs
|
(12,117 | ) | (7,027 | ) | (19,144 | ) | ||||||
|
Exploration
Expense
|
- | - | - | |||||||||
|
DD&A
|
(22,183 | ) | (3,355 | ) | (25,538 | ) | ||||||
|
Income
Tax (Expense) Recovery
|
(22,063 | ) | 1,122 | (20,941 | ) | |||||||
|
Results of
Operations
|
$ | 46,839 | $ | 343 | $ | 47,182 | ||||||
|
Year
ended December 31, 2009
|
||||||||||||
|
Net
Sales
|
$ | 248,834 | $ | 13,795 | $ | 262,629 | ||||||
|
Production
Costs
|
(33,091 | ) | (7,537 | ) | (40,628 | ) | ||||||
|
Exploration
Expense
|
- | - | - | |||||||||
|
DD&A
|
(126,261 | ) | (8,312 | ) | (134,573 | ) | ||||||
|
Income
Tax (Expense) Recovery
|
(25,824 | ) | 1,470 | (24,354 | ) | |||||||
|
Results of
Operations
|
$ | 63,658 | $ | (584 | ) | $ | 63,074 | |||||
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 for 2009 are
computed by applying the 12 month period unweighted arithmetic average of the
price as of the first day of each month within that 12 month period, unless
prices are defined by contractual arrangements, excluding escalations based on
future conditions to Gran Tierra’s after royalty share of estimated annual
future production from proved oil and gas reserves. Future cash inflows for 2008
and 2007 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 period end oil prices at December 31, 2009 were $61.04 for Colombia and
$40.98 for Argentina. The period end oil prices at December 31, 2008 were $44.60
for Colombia and $33.94 for Argentina. The period end oil prices at December 31,
2007 were $71.28 for Colombia and $38.76 for Argentina. The calculated weighted
average production costs at December 31, 2009 were $14.92 for Colombia and
$20.73 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. 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.
92
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:
|
•
|
|
no
economic value is attributed to probable and possible
reserves;
|
|
•
|
|
use
of a 10% discount rate is arbitrary;
and
|
|
•
|
|
prices
change constantly from the 12 month period unweighted arithmetic average
of the price as of the first day of each month within that 12 month
period.
|
|
Colombia
|
Argentina
|
Total
|
||||||||||
|
December 31,
2007
|
||||||||||||
|
Future
Cash Inflows
|
$ | 393,164 | $ | 79,777 | $ | 472,941 | ||||||
|
Future
Production Costs
|
(54,760 | ) | (20,001 | ) | (74,761 | ) | ||||||
|
Future
Development Costs
|
(21,350 | ) | (8,658 | ) | (30,008 | ) | ||||||
|
Future
Site Restoration Costs
|
(2,568 | ) | (617 | ) | (3,185 | ) | ||||||
|
Future
Income Tax
|
(98,998 | ) | (17,716 | ) | (116,714 | ) | ||||||
|
Future
Net Cash Flows
|
215,488 | 32,785 | 248,273 | |||||||||
|
10%
Discount Factor
|
(43,554 | ) | (8,435 | ) | (51,989 | ) | ||||||
|
Standardized
Measure
|
$ | 171,934 | $ | 24,350 | $ | 196,284 | ||||||
|
December 31,
2008
|
||||||||||||
|
Future
Cash Inflows
|
$ | 734,727 | $ | 52,856 | $ | 787,583 | ||||||
|
Future
Production Costs
|
(131,317 | ) | (19,154 | ) | (150,471 | ) | ||||||
|
Future
Development Costs
|
(159,219 | ) | (4,279 | ) | (163,498 | ) | ||||||
|
Future
Site Restoration Costs
|
(1,738 | ) | (226 | ) | (1,964 | ) | ||||||
|
Future
Income Tax
|
(123,634 | ) | (8,588 | ) | (132,222 | ) | ||||||
|
Future
Net Cash Flows
|
318,819 | 20,609 | 339,428 | |||||||||
|
10%
Discount Factor
|
(60,180 | ) | (4,126 | ) | (64,306 | ) | ||||||
|
Standardized
Measure
|
$ | 258,639 | $ | 16,483 | $ | 275,122 | ||||||
|
December 31,
2009
|
||||||||||||
|
Future
Cash Inflows
|
$ | 1,117,879 | $ | 55,076 | $ | 1,172,955 | ||||||
|
Future
Production Costs
|
(312,950 | ) | (29,140 | ) | (342,090 | ) | ||||||
|
Future
Development Costs
|
(91,867 | ) | (4,923 | ) | (96,790 | ) | ||||||
|
Future
Site Restoration Costs
|
(1,415 | ) | (566 | ) | (1,981 | ) | ||||||
|
Future
Income Tax
|
(208,237 | ) | (5,771 | ) | (214,008 | ) | ||||||
|
Future
Net Cash Flows
|
503,410 | 14,676 | 518,086 | |||||||||
|
10%
Discount Factor
|
(109,043 | ) | (2,659 | ) | (111,702 | ) | ||||||
|
Standardized
Measure
|
$ | 394,367 | $ | 12,017 | $ | 406,384 | ||||||
93
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:
|
2009
|
2008
|
2007
|
||||||||||
|
Beginning of
Year
|
$ | 275,122 | $ | 196,284 | $ | 34,868 | ||||||
|
Sales
and Transfers of Oil and Gas Produced, Net of Production
Costs
|
(222,479 | ) | (94,598 | ) | (21,428 | ) | ||||||
|
Net
Changes in Prices and Production Costs Related to Future
Production
|
147,810 | (109,116 | ) | 7,399 | ||||||||
|
Extensions,
Discoveries and Improved Recovery, Less Related Costs
|
54,388 | 115,089 | 204,151 | |||||||||
|
Development
Costs Incurred during the Period
|
59,024 | 28,084 | 5,703 | |||||||||
|
Revisions
of Previous Quantity Estimates
|
149,597 | (28,716 | ) | 34,880 | ||||||||
|
Accretion
of Discount
|
38,934 | 28,970 | 4,875 | |||||||||
|
Purchases
of Reserves in Place
|
- | 184,470 | - | |||||||||
|
Sales
of Reserves in Place
|
3,035 | - | - | |||||||||
|
Net
change in Income Taxes
|
(99,047 | ) | (45,345 | ) | (74,164 | ) | ||||||
|
End of
Year
|
$ | 406,384 | $ | 275,122 | $ | 196,284 | ||||||
2)
Summarized Quarterly Financial Information
|
Revenue
and other
Income
|
Expenses
|
Income
(Loss)
Before
Income
Taxes
|
Income
Taxes
|
Net Income
(Loss)
|
Basic
Earnings
Net
Income
(Loss) Per
Share -
Basic
|
Diluted Net
Income
(Loss) Per
Share -
Diluted
|
||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||
|
First
Quarter
|
$ | 33,565 | $ | 19,518 | $ | 14,047 | $ | (85 | ) | $ | 14,132 | $ | 0.06 | $ | 0.06 | |||||||||||||
|
Second
Quarter
|
58,511 | 82,586 | (24,075 | ) | 4,125 | (28,200 | ) | (0.12 | ) | (0.12 | ) | |||||||||||||||||
|
Third
Quarter
|
75,354 | 70,211 | 5,143 | 7,959 | (2,816 | ) | (0.01 | ) | (0.01 | ) | ||||||||||||||||||
|
Fourth
Quarter
|
96,286 | 53,106 | 43,180 | 12,355 | 30,825 | 0.13 | 0.12 | |||||||||||||||||||||
| $ | 263,716 | $ | 225,421 | $ | 38,295 | $ | 24,354 | $ | 13,941 | $ | 0.06 | $ | 0.05 | |||||||||||||||
|
2008
|
||||||||||||||||||||||||||||
|
First
Quarter
|
$ | 20,819 | $ | 10,922 | $ | 9,897 | $ | 5,221 | $ | 4,676 | $ | 0.05 | $ | 0.04 | ||||||||||||||
|
Second
Quarter
|
33,144 | 19,648 | 13,496 | 4,970 | 8,526 | 0.08 | 0.07 | |||||||||||||||||||||
|
Third
Quarter
|
40,339 | 9,480 | 30,859 | 7,872 | 22,987 | 0.20 | 0.18 | |||||||||||||||||||||
|
Fourth
Quarter (1)
|
19,727 | 29,540 | (9,813 | ) | 2,881 | (12,694 | ) | (0.07 | ) | (0.07 | ) | |||||||||||||||||
| $ | 114,029 | $ | 69,590 | $ | 44,439 | $ | 20,944 | $ | 23,495 | $ | 0.19 | $ | 0.16 | |||||||||||||||
1)
The fourth quarter reflects the results of Solana from the date of acquisition
November 14, 2008
94
None.
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. 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 of the end of the period covered by this report, as
required by Rule l3a-15(e) of the Exchange Act. Based on their evaluation, our
principal executive and principal financial officers have concluded that Gran
Tierra's disclosure controls and procedures were effective as of December 31,
2009 to provide reasonable assurance that the information required to be
disclosed by Gran Tierra in the reports that it files or submits under the
Exchange Act 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
regarding required disclosure.
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, 2009.
The
effectiveness of Gran Tierra’s internal control over financial reporting as of
December 31, 2009 has been audited by Deloitte & Touche LLP, independent
registered chartered accountants.
Changes in Internal Control Over
Financial Reporting
During
the quarter ended December 31, 2009, there were no change in Gran Tierra’s
internal control over financial reporting that has materially affected, or is
reasonably likely to materially affect, Gran Tierra’s internal control over
financial reporting.
95
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, 2009,
based on the criteria established in
Internal Control—Integrated
Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission. 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, 2009, 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 at and for the year ended
December 31, 2009 of the Company and our report dated February 26, 2010
expressed an unqualified opinion on those financial statements.
/s/
Deloitte & Touche LLP
Independent
Registered Chartered Accountants
Calgary,
Canada
February
26, 2010
96
Not
applicable.
None.
The
information required 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 2010 Annual Meeting of
Stockholders (our “Proxy Statement”), a copy of which will be filed with the
Securities and Exchange Commission on or before April 30, 2010.
The
information required 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
3.
The
information required with respect to procedures by which security holders may
recommend nominees to our Board of Directors, the composition of our Audit
Committee, and whether we have an “audit committee financial expert”, 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/corporate-responsibility.html
.
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/corporate-responsibility.html
. 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 2009.
The
information required regarding the compensation of our directors and executive
officers is incorporated herein by reference from the information contained in
the sections entitled “Executive Compensation and Related Information,”
“Director Compensation,” and in the section entitled “Proposal 1 - Election of
Directors” in our Proxy Statement under the headings “Compensation Committee
Report” and “Compensation Committee Interlocks and Insider
Participation”.
The
information required regarding security ownership of our 5% or greater
stockholders and of our directors and management is incorporated herein by
reference from the information contained in the section entitled “Security
Ownership of Certain Beneficial Owners and Management” in our Proxy
Statement.
97
The
information required regarding our equity compensation plans as of December 31,
2009 is incorporated herein by reference from the information contained in the
section entitled “Stockholder Approval of Stock Plans” in our Proxy
Statement.
The
information required regarding related transactions is incorporated herein by
reference from the information contained in the section entitled “Certain
Relationships and Related Transactions” and, with respect to director
independence, the section entitled “Proposal 1 - Election of Directors”, in our
Proxy Statement.
The
information required is incorporated herein by reference from the information
contained in the sections entitled “Principal Accountant Fees and Services” and
“Audit Committee Pre-Approval Policies and Procedures” in our Proxy
Statement.
(a) The
following documents are filed as part of this Annual Report on Form
10-K:
(1)
Financial Statements
The
following documents are included as Part II, Item 8. of this Annual Report on
Form 10-K:
|
Page
|
||
|
Report
of Independent Registered Chartered Accountants
|
65
|
|
|
Consolidated
Statements of Operations and Retained Earnings (Accumulated
Deficit)
|
66
|
|
|
Consolidated
Balance Sheets
|
67
|
|
|
Consolidated
Statements of Cash Flow
|
69
|
|
|
Consolidated
Statements of Shareholders’ Equity
|
71
|
|
|
Notes
to the Consolidated Financial Statements
|
72
|
|
|
Supplementary
Data (Unaudited)
|
92
|
(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.
98
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.
|
GRAN
TIERRA ENERGY INC.
|
||||
|
Date:
|
February 26,
2010
|
By:
|
/s/
Dana Coffield
|
|
|
Dana
Coffield
|
||||
|
Chief
Executive Officer and President
|
||||
|
(Principal
Executive Officer)
|
||||
|
Date:
|
February 26,
2010
|
By:
|
/s/
Martin Eden
|
|
|
Martin
Eden
|
||||
|
Chief
Financial Officer
|
||||
|
(Principal
Financial and Accounting
Officer)
|
||||
99
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 23,
2010
|
||
|
Dana
Coffield
|
(Principal
Executive Officer)
|
|||
|
/s/
Martin Eden
|
Chief
Financial Officer
|
February 23,
2010
|
||
|
Martin
Eden
|
(Principal Financial and Accounting Officer)
|
|||
|
/s/
Jeffrey Scott
|
Chairman
of the Board, Director
|
February 23,
2010
|
||
|
Jeffrey
Scott
|
||||
|
/s/
Verne Johnson
|
Director
|
February 23,
2010
|
||
|
Verne
Johnson
|
||||
|
/s/
Nicholas G. Kirton
|
Director
|
February 23,
2010
|
||
|
Nicholas
G. Kirton
|
||||
|
/s/
J. Scott Price
|
Director
|
February 23,
2010
|
||
|
J.
Scott Price
|
||||
|
/s/
Ray Antony
|
Director
|
February 23,
2010
|
||
|
Ray
Antony
|
||||
|
|
Director
|
|
||
|
Walter
Dawson
|
100
EXHIBIT
INDEX
|
Exhibit
No.
|
Description
|
Reference
|
||
|
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
|
Amended
and Restated Articles of Incorporation.
|
Incorporated
by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
3.2
|
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 and 3.2.
|
|||
|
4.2
|
Form
of Warrant issued to investors in connection with the private offering 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).
|
||
|
4.4
|
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).
|
||
|
4.5
|
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).
|
||
|
4.6
|
Reference
is made to Exhibits 10.1 through 10.10, and 10.55,
below.
|
|||
|
10.1
|
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).
|
101
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.2
|
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).
|
||
|
10.3
|
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).
|
||
|
10.4
|
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).
|
||
|
10.5
|
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).
|
||
|
10.6
|
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).
|
||
|
10.7
|
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).
|
||
|
10.8
|
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).
|
||
|
10.9
|
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).
|
||
|
10.10
|
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).
|
||
|
10.11
|
2007
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).
|
102
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.12
|
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).
|
||
|
10.13
|
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).
|
||
|
10.14
|
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).
|
||
|
10.15
|
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).
|
||
|
10.16
|
2005
Equity Incentive Plan. *
|
Incorporated
by reference to Exhibit 10.11 to the Current Report on Form 8-K filed
with the Securities and Exchange Commission on November 10, 2005
(File No. 333-111656).
|
||
|
10.17
|
2008
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 December 17, 2008.
|
||
|
10.18
|
Employment
Agreement, dated November 4, 2008, between Gran Tierra Energy Inc. and
Dana Coffield.*
|
Incorporated
by reference to Exhibit 10.57 to the Annual Report on Form 10-K, filed
with the SEC on February 27, 2009.
|
||
|
10.19
|
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.
|
||
|
10.20
|
Employment
Agreement, dated November , 2008, between Gran Tierra Energy Inc. and
Edgar Dyes.*
|
Incorporated
by reference to Exhibit 10.59 to the Annual Report on Form 10-K, filed
with the SEC on February 27, 2009.
|
||
|
10.21
|
Employment
Agreement, dated November 4, 2008, between Gran Tierra Energy Inc. and Max
Wei. *
|
Incorporated
by reference to Exhibit 10.60 to the Annual Report on Form 10-K, filed
with the SEC on February 27, 2009.
|
||
|
10.22
|
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.
|
||
|
10.23
|
Employment
Agreement, dated November 23, 2009, between Gran Tierra Energy Inc. and
Julian Garcia *
|
Filed
herewith.
|
||
|
10.24
|
Offer
Letter between Gran Tierra Energy Inc. and Shane P. O’Leary dated January
26, 2009 *
|
Incorporated
by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with
the SEC on February 4, 2009.
|
103
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.25
|
Employment
Agreement between Gran Tierra Energy Inc. and Shane P. O’Leary dated as of
January 26, 2009. *
|
Incorporated
by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with
the SEC on February 4, 2009.
|
||
|
10.26
|
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).
|
||
|
10.27
|
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)
|
||
|
10.28
|
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).
|
||
|
10.29
|
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.
|
||
|
10.30
|
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.
|
||
|
10.31
|
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.
|
||
|
10.32
|
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.
|
||
|
10.33
|
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.
|
||
|
10.34
|
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.
|
104
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.35
|
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.
|
||
|
10.36
|
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.
|
||
|
10.37
|
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).
|
105
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.46
|
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.
|
||
|
10.47
|
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.
|
||
|
10.48
|
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.
|
||
|
10.49
|
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.
|
||
|
10.50
|
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.
|
||
|
10.51
|
Assignment
and Assumption Agreement, dated as of August 24, 2009, by and among Gran
Tierra Energy Inc., Gran Tierra Energy Cayman Islands Inc., and Standard
Bank PLC.
|
Incorporated
by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.52
|
Amended
and Restated Credit Agreement, dated as of August 24, 2009, by and among
Gran Tierra Energy Inc., Gran Tierra Energy Colombia, Ltd., Argosy Energy,
LLC, Solana Petroleum Exploration (Colombia) Limited, Solana Resources
Limited, and Standard Bank PLC.
|
Incorporated
by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.53
|
First
Priority Open Pledge Agreement over Credit Rights Derived from Hydrocarbon
Commercial Sales Agreements, dated as of August 24, 2009, by and between
Solana Petroleum Exploration (Colombia) Limited and Standard Bank
PLC.
|
Incorporated
by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.54
|
First
Priority Open Pledge Agreement over a Commercial Establishment, dated as
of August 24, 2009, by and between Solana Petroleum Exploration (Colombia)
Limited and Standard Bank PLC.
|
Incorporated
by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.55
|
Amended
and Restated First Priority Open Pledge Agreement over Credit Rights
Derived from Crude Oil Commercial Sales Agreements, dated as of August 24,
2009, by and between Gran Tierra Energy Colombia, Ltd., and Standard Bank
PLC.
|
Incorporated
by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6,
2010.
|
106
|
Exhibit
No.
|
Description
|
Reference
|
||
|
10.56
|
Cancellation
of BNP Pledge over Credit Rights, dated as of August 20, 2009, by BNP
Paribas.
|
Incorporated
by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.57
|
Cancellation
of BNP Pledge over Commercial Establishment, dated as of August 21, 2009,
by BNP Paribas.
|
Incorporated
by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.58
|
Collection
Account Pledge Agreement, dated as of August 24, 2009, by and between
Solana Petroleum Exploration (Colombia) Limited and Standard Bank
PLC.
|
Incorporated
by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.59
|
Deposit
Account Control Agreement, dated as of August 24, 2009, by and among
Solana Petroleum Exploration (Colombia) Limited, BNP Paribas, and Standard
Bank PLC.
|
Incorporated
by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q/A, filed
with the SEC on January 6, 2010.
|
||
|
10.60
|
Letter
regarding Pledge Agreements, dated as of August 24, 2009, by and among the
Gran Tierra Energy Cayman Islands Inc, Gran Tierra Energy Colombia, Ltd.,
Argosy Energy, LLC, GTE Colombia Holdings LLC, and Standard Bank
PLC.
|
Incorporated
by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q/A,
filed with the SEC on January 6, 2010.
|
||
|
10.61
|
Release
of Share Pledge Agreement, dated as of August 24, 2009, by and between
Gran Tierra Energy Inc. and Standard Bank PLC.
|
Incorporated
by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q/A,
filed with the SEC on January 6, 2010.
|
||
|
10.62
|
Employment
Agreement, dated July 1, 2009, between Gran Tierra Energy Inc. and Julio
Moreira *
|
Filed
herewith.
|
||
|
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.
|
||
|
99.1
|
|
Gran
Tierra Energy Inc. Reserves Assessment and Evaluation of Argentine and
Colombian Oil and Gas Properties Corporate Summary, effective December 31,
2009
|
|
Filed
herewith.
|
*
Management contract or compensatory plan or arrangement.
107
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. ReservedPart IIItem 5. Market For Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosure About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9a(t). Controls and ProceduresItem 9a(t)Item 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement Schedules