Attached files
file | filename |
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EX-32.1 - GRAN TIERRA ENERGY INC. | v184077_ex32-1.htm |
EX-31.1 - GRAN TIERRA ENERGY INC. | v184077_ex31-1.htm |
EX-31.2 - GRAN TIERRA ENERGY INC. | v184077_ex31-2.htm |
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-Q
x
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
FOR
THE QUARTERLY PERIOD ENDED March 31,
2010
|
OR
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
FOR
THE TRANSITION PERIOD FROM __________
TO __________
|
Commission
file number
001-34018
GRAN
TIERRA ENERGY INC.
(Exact
name of registrant as specified in its charter)
Nevada
|
98-0479924
|
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
employer
identification
number)
|
|
300,
625 11th
Avenue S.W.
Calgary,
Alberta, Canada
|
T2R
0E1
|
|
(Address
of principal executive offices)
|
(Zip
code)
|
(403) 265-3221
(Registrant’s
telephone number,
including
area code)
300, 611
10th
Avenue SW
Calgary,
Alberta, Canada T2R 0B2
(Former
Address, Changed Since Last Report)
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 o
Indicate
by check mark whether the registrant 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 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.
Accelerated
Filer
o
|
|
Non-Accelerated
Filer
o
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). YES o NO x
On May 7,
2010, the following numbers of shares of the registrant’s capital stock were
outstanding: 233,606,307 shares of the registrant’s Common Stock, $0.001 par
value; one share of Special A Voting Stock, $0.001 par
value, representing 8,446,032 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 11,566,398 shares of Gran Tierra Exchangeco
Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common
Stock.
Page
|
||
PART
I - FINANCIAL INFORMATION
|
||
ITEM
1.
|
FINANCIAL
STATEMENTS
|
3
|
ITEM
2.
|
MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
16
|
ITEM
3.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
28
|
ITEM
4.
|
CONTROLS
AND PROCEDURES
|
28
|
ITEM
4T.
|
CONTROLS
AND PROCEDURES
|
29
|
PART
II - OTHER INFORMATION
|
||
ITEM
1.
|
LEGAL
PROCEEDINGS
|
29
|
ITEM
1A.
|
RISK
FACTORS
|
29
|
ITEM
2.
|
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
38
|
ITEM
6.
|
EXHIBITS
|
39
|
SIGNATURES
|
39
|
|
EXHIBIT
INDEX
|
40
|
2
PART I -
FINANCIAL INFORMATION
ITEM 1 - FINANCIAL
STATEMENTS
Condensed
Consolidated Statements of Operations and Retained Earnings
(Unaudited)
(Thousands
of U.S. Dollars, Except Share and Per Share Amounts)
Three
Months Ended March 31,
|
||||||||
2010
|
2009
|
|||||||
REVENUE
AND OTHER INCOME
|
||||||||
Oil
and natural gas sales
|
$ | 92,932 | $ | 33,151 | ||||
Interest
|
178 | 414 | ||||||
93,110 | 33,565 | |||||||
EXPENSES
|
||||||||
Operating
|
10,185 | 7,086 | ||||||
Depletion,
depreciation, accretion, and impairment
|
40,343 | 27,529 | ||||||
General
and administrative
|
7,190 | 5,125 | ||||||
Derivative
financial instruments gain (Note 10)
|
(44 | ) | - | |||||
Foreign
exchange loss (gain)
|
14,294 | (20,222 | ) | |||||
71,968 | 19,518 | |||||||
INCOME
BEFORE INCOME TAXES
|
21,142 | 14,047 | ||||||
Income
tax (expense) recovery (Note 7)
|
(11,182 | ) | 85 | |||||
NET
INCOME AND COMPREHENSIVE INCOME
|
9,960 | 14,132 | ||||||
RETAINED
EARNINGS, BEGINNING OF PERIOD
|
20,925 | 6,984 | ||||||
RETAINED
EARNINGS, END OF PERIOD
|
$ | 30,885 | $ | 21,116 | ||||
NET
INCOME PER SHARE — BASIC
|
$ | 0.04 | $ | 0.06 | ||||
NET
INCOME PER SHARE — DILUTED
|
$ | 0.04 | $ | 0.06 | ||||
WEIGHTED
AVERAGE SHARES OUTSTANDING - BASIC (Note 5)
|
248,818,662 | 238,907,060 | ||||||
WEIGHTED
AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)
|
256,863,106 | 248,914,219 |
(See
notes to the condensed consolidated financial statements)
3
Gran
Tierra Energy Inc.
Condensed
Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars,
Except Share Amounts)
March
31,
|
December
31,
|
|||||||
2010
|
2009
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
$ | 265,676 | $ | 270,786 | ||||
Restricted
cash
|
240 | 1,630 | ||||||
Accounts
receivable
|
87,024 | 35,639 | ||||||
Inventory
(Note 2)
|
4,160 | 4,879 | ||||||
Taxes
receivable
|
1,721 | 1,751 | ||||||
Prepaids
|
2,489 | 1,820 | ||||||
Deferred
tax assets (Note 7)
|
4,311 | 4,252 | ||||||
Total
Current Assets
|
365,621 | 320,757 | ||||||
Oil
and Gas Properties (using the full cost method of
accounting)
|
||||||||
Proved
|
454,217 | 474,679 | ||||||
Unproved
|
234,400 | 234,889 | ||||||
Total
Oil and Gas Properties
|
688,617 | 709,568 | ||||||
Other
capital assets
|
4,039 | 3,175 | ||||||
Total
Property, Plant and Equipment (Note 4)
|
692,656 | 712,743 | ||||||
Other
Long Term Assets
|
||||||||
Restricted
cash
|
840 | 162 | ||||||
Deferred
tax assets (Note 7)
|
6,903 | 7,218 | ||||||
Other
long term assets
|
315 | 347 | ||||||
Goodwill
|
102,581 | 102,581 | ||||||
Total
Other Long Term Assets
|
110,639 | 110,308 | ||||||
Total
Assets
|
$ | 1,168,916 | $ | 1,143,808 | ||||
4
Gran
Tierra Energy Inc.
Condensed
Consolidated Balance Sheets (Unaudited) (continued)
(Thousands of U.S. Dollars,
Except Share Amounts)
March
31,
|
December
31,
|
|||||||
2010
|
2009
|
|||||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable (Note 8)
|
$ | 22,149 | $ | 36,786 | ||||
Accrued
liabilities (Note 8)
|
35,204 | 40,229 | ||||||
Derivative
financial instruments (Note 10)
|
- | 44 | ||||||
Taxes
payable
|
40,804 | 28,087 | ||||||
Asset
retirement obligation (Note 6)
|
450 | 450 | ||||||
Total
Current Liabilities
|
98,607 | 105,596 | ||||||
Long
Term Liabilities
|
||||||||
Deferred
tax liabilities (Note 7)
|
218,981 | 216,625 | ||||||
Deferred
remittance tax (Note 7)
|
944 | 903 | ||||||
Asset
retirement obligation (Note 6)
|
4,387 | 4,258 | ||||||
Total
Long Term Liabilities
|
224,312 | 221,786 | ||||||
Commitments
and Contingencies (Note 9)
|
||||||||
Shareholders’
Equity
|
||||||||
Common
shares (Note 5)
|
3,022 | 1,431 | ||||||
(232,937,045
and 219,459,361 common shares and 20,488,841 and 24,639,513 exchangeable
shares, par value $0.001 per share, issued and outstanding as at March 31,
2010 and December 31, 2009 respectively)
|
||||||||
Additional
paid in capital
|
808,912 | 766,963 | ||||||
Warrants
|
3,178 | 27,107 | ||||||
Retained
earnings
|
30,885 | 20,925 | ||||||
Total
Shareholders’ Equity
|
845,997 | 816,426 | ||||||
Total
Liabilities and Shareholders’ Equity
|
$ | 1,168,916 | $ | 1,143,808 |
(See
notes to the condensed consolidated financial statements)
5
Gran
Tierra Energy Inc.
Condensed
Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
Three
Months Ended March 31,
|
||||||||
2010
|
2009
|
|||||||
Operating
Activities
|
||||||||
Net
income
|
$ | 9,960 | $ | 14,132 | ||||
Adjustments
to reconcile net income to net cash provided by (used in) operating
activities:
|
||||||||
Depletion,
depreciation, accretion, and impairment
|
40,343 | 27,529 | ||||||
Deferred
taxes
|
(10,054 | ) | (3,982 | ) | ||||
Stock
based compensation (Note 5)
|
1,362 | 1,125 | ||||||
Unrealized
(gain) loss on financial instruments (Note 10)
|
(44 | ) | 87 | |||||
Unrealized
foreign exchange loss (gain)
|
12,707 | (18,298 | ) | |||||
Settlement
of asset retirement obligations (Note 6)
|
- | (52 | ) | |||||
Net
changes in non-cash working capital
|
||||||||
Accounts
receivable
|
(46,208 | ) | (25,260 | ) | ||||
Inventory
|
97 | (57 | ) | |||||
Prepaids
|
(669 | ) | (460 | ) | ||||
Accounts
payable and accrued liabilities
|
(17,796 | ) | (3,176 | ) | ||||
Taxes
receivable and payable
|
12,747 | 774 | ||||||
Net
cash provided by (used in) operating activities
|
2,445 | (7,638 | ) | |||||
Investing
Activities
|
||||||||
Restricted
cash
|
712 | - | ||||||
Additions
to property, plant and equipment
|
(27,072 | ) | (21,627 | ) | ||||
Proceeds
from disposition of oil and gas property
|
600 | - | ||||||
Long
term assets and liabilities
|
32 | (299 | ) | |||||
Net
cash used in investing activities
|
(25,728 | ) | (21,926 | ) | ||||
Financing
Activities
|
||||||||
Proceeds
from issuance of common shares
|
18,173 | 520 | ||||||
Net
cash provided by financing activities
|
18,173 | 520 | ||||||
Net
decrease in cash and cash equivalents
|
(5,110 | ) | (29,044 | ) | ||||
Cash
and cash equivalents, beginning of period
|
270,786 | 176,754 | ||||||
Cash
and cash equivalents, end of period
|
$ | 265,676 | $ | 147,710 | ||||
Cash
|
$ | 101,580 | $ | 22,877 | ||||
Term
deposits
|
164,096 | 124,833 | ||||||
Cash
and cash equivalents, end of period
|
$ | 265,676 | $ | 147,710 | ||||
Supplemental
cash flow disclosures:
|
||||||||
Cash
paid for taxes
|
$ | 10,147 | $ | 1,540 | ||||
Non-cash
investing activities:
|
||||||||
Non-cash
working capital related to property, plant and equipment
|
$ | 10,328 | $ | 8,413 |
(See
notes to the condensed consolidated financial statements)
6
Gran
Tierra Energy Inc.
Condensed
Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands
of U.S. Dollars)
Three
Months Ended
|
Year
Ended
|
|||||||
March
31, 2010
|
December
31, 2009
|
|||||||
Share
Capital
|
||||||||
Balance,
beginning of period
|
$ | 1,431 | $ | 226 | ||||
Issue
of common shares
|
1,591 | 1,205 | ||||||
Balance,
end of period
|
3,022 | 1,431 | ||||||
Additional
Paid in Capital
|
||||||||
Balance,
beginning of period
|
766,963 | 754,832 | ||||||
Issue
of common shares
|
13,995 | 2,650 | ||||||
Exercise
of warrants (Note 5)
|
23,929 | 2,777 | ||||||
Exercise
of stock options (Note 5)
|
2,587 | 1,080 | ||||||
Stock
based compensation expense (Note 5)
|
1,438 | 5,624 | ||||||
Balance,
end of period
|
808,912 | 766,963 | ||||||
Warrants
|
||||||||
Balance,
beginning of period
|
27,107 | 29,884 | ||||||
Exercise
of warrants (Note 5)
|
(23,929 | ) | (2,777 | ) | ||||
Balance,
end of period
|
3,178 | 27,107 | ||||||
Retained
Earnings
|
||||||||
Balance,
beginning of period
|
20,925 | 6,984 | ||||||
Net
income
|
9,960 | 13,941 | ||||||
Balance,
end of period
|
30,885 | 20,925 | ||||||
Total
Shareholders’ Equity
|
$ | 845,997 | $ | 816,426 |
(See
notes to the condensed consolidated financial statements)
7
Gran
Tierra Energy Inc.
Notes
to the Condensed Consolidated Financial Statements (Unaudited)
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
These
interim unaudited 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 interim consolidated financial statements, and
revenues and expenses during the reporting period. In the opinion of the
Company’s management, all adjustments (all of which are normal and recurring)
that have been made are necessary to fairly state the consolidated financial
position of the Company as at March 31, 2010, the results of its operations and
its cash flows for the three month periods ended March 31, 2010 and
2009.
The note
disclosure requirements of annual consolidated financial statements provide
additional disclosures to that required for interim consolidated financial
statements. Accordingly, these interim consolidated financial statements should
be read in conjunction with the Company’s consolidated financial statements as
at and for the year ended December 31, 2009 included in the Company’s 2009
Annual Report on Form 10-K, filed with the Securities and Exchange Commission
(“SEC”) on February 26, 2010. The Company’s significant accounting policies are
described in Note 2 of the consolidated financial statements which are included
in the Company’s 2009 Annual Report on Form 10-K and are the same policies
followed in these unaudited interim consolidated financial statements, except as
disclosed below. The Company has evaluated all subsequent events through to the
date these unaudited interim consolidated financial statements were
issued.
Inventory
Crude oil
inventories at March 31, 2010 and December 31, 2009 are $2.9 million and $3.8
million, respectively. Supplies at March 31, 2010 and December 31, 2009 are $1.3
million and $1.1 million, respectively.
New Accounting
Pronouncements
Variable
Interest Entities
In June
2009, the Financial Accounting Standards Board (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
implementation of this standard did not materially impact the Company’s
consolidated financial position, operating results or cash flows.
Subsequent
Events
In
February 2010, the FASB issued Accounting Standards Update (“ASU”), "Subsequent
Events (Topic 855)." The amendments remove the requirements for an
SEC filer to disclose a date, in both issued and revised financial statements,
through which subsequent events have been reviewed. This ASU was
effective upon issuance. The implementation of this update did not
materially impact the Company’s consolidated financial position, operating
results or cash flows.
Fair
Value Measurements
In
January 2010, the FASB issued ASU, “Fair Value Measurements and Disclosures
(Topic 820): Improving Disclosures about Fair Value Measurements”. This ASU
amends existing disclosure requirements about fair value measurements by adding
required disclosures about items transferred into and out of levels 1 and 2 in
the fair value hierarchy; adding separate disclosures about purchases, sales,
issuances, and settlements relative to level 3 measurements; and clarifying,
among other things, the existing fair value disclosures about the level of
disaggregation. This is effective for interim and annual reporting periods
beginning after December 15, 2009, except for the disclosures about purchases,
sales, issuances, and settlements in the roll forward of activity in Level 3
fair value measurements. Those disclosures are effective for fiscal
years beginning after December 15, 2010, and for interim periods within those
fiscal years. Early adoption is permitted. The
implementation of this update on January 1, 2010 did not materially impact the
Company’s consolidated financial position, operating results or cash
flows.
3. 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 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.
8
The
following tables present information on the Company’s reportable geographic
segments:
Three
Months Ended March 31, 2010
|
||||||||||||||||
(Thousands
of U.S. Dollars except per unit of production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 89,433 | $ | 3,499 | $ | - | $ | 92,932 | ||||||||
Interest
income
|
77 | 16 | 85 | 178 | ||||||||||||
Depreciation,
depletion and accretion
|
35,006 | 1,567 | 70 | 36,643 | ||||||||||||
Impairment
of carrying value of oil and natural gas properties
|
- | 3,700 | - | 3,700 | ||||||||||||
Depreciation,
depletion and accretion - per unit of production
|
27.58 | 20.59 | - | 27.24 | ||||||||||||
Impairment
of carrying value of oil and natural gas properties - per unit of
production
|
- | 48.61 | - | 2.75 | ||||||||||||
Segment
income (loss) before income taxes
|
28,760 | (4,644 | ) | (2,974 | ) | 21,142 | ||||||||||
Segment
capital expenditures
|
$ | 17,553 | $ | 660 | $ | 1,291 | $ | 19,504 | ||||||||
Three
Months Ended March 31, 2009
|
||||||||||||||||
(Thousands
of U.S. Dollars except per unit of production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 30,275 | $ | 2,876 | $ | - | $ | 33,151 | ||||||||
Interest
income
|
224 | 40 | 150 | 414 | ||||||||||||
Depreciation,
depletion and accretion
|
25,923 | 1,530 | 76 | 27,529 | ||||||||||||
Depreciation,
depletion and accretion - per unit of production
|
30.16 | 18.26 | - | 29.19 | ||||||||||||
Segment
income (loss) before income taxes
|
17,581 | (446 | ) | (3,088 | ) | 14,047 | ||||||||||
Segment
capital expenditures
|
$ | 17,932 | $ | 448 | $ | 786 | $ | 19,166 | ||||||||
As
at March 31, 2010
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant and equipment
|
$ | 665,147 | $ | 19,909 | $ | 7,600 | $ | 692,656 | ||||||||
Goodwill
|
102,581 | - | - | 102,581 | ||||||||||||
Other
assets
|
150,859 | 13,253 | 209,567 | 373,679 | ||||||||||||
Total
Assets
|
$ | 918,587 | $ | 33,162 | $ | 217,167 | $ | 1,168,916 | ||||||||
As
at December 31, 2009
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant and 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 |
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 2010, the Company has one significant customer for its Colombian
crude oil, Ecopetrol S.A. (“Ecopetrol”), a Colombian government agency. Sales to
Ecopetrol accounted for 96% of the Company’s revenues in the first quarter of
2010. In Argentina, the Company has one significant customer, Refineria del
Norte S.A (“Refiner”). Sales to Refiner accounted for 3% of the Company’s
revenues in the first quarter of 2010.
9
4. Property, Plant and
Equipment
As
at March 31, 2010
|
As
at December 31, 2009
|
|||||||||||||||||||||||
(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
|
$ | 667,151 | $ | (212,934 | ) | $ | 454,217 | $ | 648,061 | $ | (173,382 | ) | $ | 474,679 | ||||||||||
Unproved
|
234,400 | - | 234,400 | 234,889 | - | 234,889 | ||||||||||||||||||
901,551 | (212,934 | ) | 688,617 | 882,950 | (173,382 | ) | 709,568 | |||||||||||||||||
Furniture
and fixtures and leasehold improvements
|
4,294 | (2,206 | ) | 2,088 | 3,843 | (2,185 | ) | 1,658 | ||||||||||||||||
Computer
equipment
|
3,628 | (1,947 | ) | 1,681 | 3,148 | (1,907 | ) | 1,241 | ||||||||||||||||
Automobiles
|
542 | (272 | ) | 270 | 513 | (237 | ) | 276 | ||||||||||||||||
Total
Property, Plant and Equipment
|
$ | 910,015 | $ | (217,359 | ) | $ | 692,656 | $ | 890,454 | $ | (177,711 | ) | $ | 712,743 |
Depreciation,
depletion, accretion and impairment for the three months ended March 31,
2010 included a $3.7 million ceiling test impairment loss in our Argentina cost
center.
During
the three months ended March 31, 2010, the Company capitalized $0.6 million
(year ended December 31, 2009 - $1.6 million) of general and administrative
expenses related to the Colombian full cost center, including $0.1 million (year
ended December 31, 2009 - $0.2 million) of stock based compensation expense, and
$0.2 million (year ended December 31, 2009 - $0.6 million) of general and
administrative expenses in the Argentina full cost center, including $25,000
(year ended December 31, 2009 - $0.1 million) of stock based
compensation.
The
unproved oil and natural gas properties at March 31, 2010 consist of exploration
lands held in Colombia, Argentina and Peru. As at March 31, 2010, the Company
had $228.1 million (December 31, 2009 - $229.1 million) in unproved assets
in Colombia, $0.5 million (December 31, 2009 - $0.4 million) of unproved
assets in Argentina and $5.8 million (December 31, 2009 - $5.4 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.
5. 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 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 March 31, 2010, outstanding share capital consists of 232,937,045
common voting shares of the Company, 12,042,809 exchangeable shares of Gran
Tierra Exchange Co., automatically exchangeable on November 14, 2013, and
8,446,032 exchangeable shares of Goldstrike Exchange Co., automatically
exchangeable on November 10, 2012. 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.
Warrants
At March
31, 2010, the Company has 3,846,362 warrants outstanding to purchase 1,923,181
common shares for $1.25 per share, expiring between September 1, 2010 and
February 2, 2011, and 9,992,520 warrants outstanding to purchase 4,996,260
common shares for $1.05 per share, expiring between June 20, 2012 and June 30,
2012. For the three months ended March 31, 2010, 8,118,018 common shares
were issued upon the exercise of 9,090,098 warrants (three months ended March
31, 2009, 789,317 common shares were issued upon the exercise of 2,069,300
warrants). Included in warrants exercised in the three months ended March
31, 2010 are 7,145,938 warrants to purchase 7,145,938 common shares for $14.4
million, assumed on the acquisition of Solana Resources Limited in November
2008.
10
Stock
Options
As at
March 31, 2010, 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 three months after 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 three months ended March 31, 2010, 1,208,994 common
shares were issued upon the exercise of 1,208,994 stock options (three months
ended March 31, 2009 – 43,820). The following options are outstanding as of
March 31, 2010:
Number of
|
Weighted Average
|
|||||||
Outstanding
|
Exercise Price
|
|||||||
Options
|
$/Option
|
|||||||
Balance,
December 31, 2009
|
11,088,616 | $ | 2.43 | |||||
Granted
in 2010
|
2,700,000 | 5.90 | ||||||
Exercised
in 2010
|
(1,208,994 | ) | (2.14 | ) | ||||
Forfeited
in 2010
|
(111,668 | ) | (2.48 | ) | ||||
Balance,
March 31, 2010
|
12,467,954 | $ | 3.20 |
The
weighted average grant date fair value for options granted in 2010 was $3.33.
The intrinsic value of options exercised for the three months ended March 31,
2010 was $4.5 million (three months ended March 31, 2009 -
$75,890).
The table
below summarizes stock options outstanding at March 31, 2010:
Number
of
|
Weighted
Average
|
Weighted
|
||||||||||
Outstanding
|
Exercise
Price
|
Average
|
||||||||||
Range
of Exercise Prices ($/option)
|
Options
|
$/Option
|
Expiry
Years
|
|||||||||
0.50
to 1.30
|
1,965,671 | $ | 1.05 | 6.1 | ||||||||
1.31
to 2.00
|
320,974 | 1.75 | 6.8 | |||||||||
2.01
to 3.50
|
6,401,309 | 2.45 | 8.4 | |||||||||
3.51
to 5.50
|
585,000 | 4.42 | 9.5 | |||||||||
5.51
to 7.75
|
3,195,000 | 5.96 | 9.8 | |||||||||
Total
|
12,467,954 | $ | 3.20 | 8.4 |
The
aggregate intrinsic value of options outstanding at March 31, 2010 is $37.7
million based on the Company’s closing stock price of $5.90 for that date. At
March 31, 2010, there was $11.3 million of unrecognized compensation cost
related to unvested stock options which is expected to be recognized over the
next three years.
For the
three months ended March 31, 2010, the stock based compensation expense was
$1.4 million (three months ended March 31, 2009 - $1.3 million) of which $1.1
million (three months ended March 31, 2009 - $1.0 million) was recorded in
general and administrative expense and $0.2 million was recorded in operating
expense in the consolidated statement of operations (three months ended March
31, 2009 – $0.1 million). For the three months ended March 31, 2010, $0.1
million of stock based compensation was capitalized as part of exploration and
development costs (three months ended March 31, 2009 – $0.2
million).
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.
Three
Months Ended March 31,
|
||||
2010
|
2009
|
|||
Dividend
yield (per share)
|
$
|
nil
|
$
|
nil
|
Volatility
|
90%
|
97%
|
||
Risk-free
interest rate
|
0.4%
|
0.6%
|
||
Expected
term
|
3
years
|
3
years
|
||
Estimated
forfeiture percentage (per year)
|
10%
|
10%
|
11
Weighted Average Shares
Outstanding
Three
Months Ended March 31,
|
||||||||
2010
|
2009
|
|||||||
Weighted
average number of common and exchangeable shares
outstanding
|
248,818,662 | 238,907,060 | ||||||
Shares
issuable pursuant to warrants
|
5,518,333 | 9,903,126 | ||||||
Shares
issuable pursuant to stock options
|
5,013,174 | 2,750,940 | ||||||
Shares
to be purchased from proceeds of stock options
|
(2,487,063 | ) | (2,646,907 | ) | ||||
Weighted
average number of diluted common and exchangeable shares
outstanding
|
256,863,106 | 248,914,219 |
Net Income Per
Share
For the
three month period ended March 31, 2010, options to purchase 3,195,000 common
shares were excluded from the diluted income per share calculation as the
instruments were anti-dilutive. For the three months ended March 31, 2009,
options to purchase 504,850 common shares were excluded from the diluted income
per share calculation as the instruments were anti-dilutive.
6. Asset Retirement
Obligation
As
at March 31, 2010, the Company’s asset retirement obligation was
comprised of a Colombian obligation in the amount of $3.6 million (December 31,
2009 - $3.5 million) and an Argentine obligation in the amount of $1.2 million
(December 31, 2009 - $1.2 million). The undiscounted asset retirement obligation
is $7.8 million. Changes in the carrying amounts of the asset retirement
obligations associated with the Company’s oil and natural gas properties were as
follows:
Three
Months Ended
|
Year
Ended
|
|||||||
March
31, 2010
|
December
31, 2009
|
|||||||
Balance,
beginning of period
|
$ | 4,708 | $ | 4,251 | ||||
Settlements
|
- | (52 | ) | |||||
Disposal
|
- | (734 | ) | |||||
Liability
incurred
|
39 | 921 | ||||||
Foreign
exchange
|
17 | 24 | ||||||
Accretion
|
73 | 298 | ||||||
Balance,
end of period
|
$ | 4,837 | $ | 4,708 | ||||
Asset
retirement obligation - current
|
$ | 450 | $ | 450 | ||||
Asset
retirement obligation - long term
|
4,387 | 4,258 | ||||||
Balance,
end of period
|
$ | 4,837 | $ | 4,708 |
7. Income
Taxes
The
income tax expense (recovery) reported differ from the amount computed by
applying the US statutory rate to income before income taxes for the following
reasons:
Three
Months Ended March 31,
|
||||||||
(Thousands
of U.S. Dollars)
|
2010
|
2009
(1)
|
||||||
Income
before income taxes
|
$ | 21,142 | $ | 14,047 | ||||
35.00 | % | 35.00 | % | |||||
Income
tax expense expected
|
7,400 | 4,916 | ||||||
Permanent
differences
|
1,816 | 440 | ||||||
Foreign
currency translation adjustments
|
4,166 | (5,926 | ) | |||||
Impact
of foreign taxes
|
(840 | ) | 97 | |||||
Enhanced
tax depreciation incentive
|
(1,292 | ) | (859 | ) | ||||
Stock
based compensation
|
449 | 333 | ||||||
Increase
in valuation allowance
|
1,721 | 2,726 | ||||||
Partnership
and branch loss pick-up in the United States and Canada
|
(1,248 | ) | (1,812 | ) | ||||
Other
|
(990 | ) | - | |||||
Total
income tax expense (recovery)
|
$ | 11,182 | $ | (85 | ) | |||
Current
income tax
|
21,236 | 3,897 | ||||||
Deferred
tax recovery
|
(10,054 | ) | (3,982 | ) | ||||
Total
income tax expense (recovery)
|
$ | 11,182 | $ | (85 | ) |
(1)
|
For
the three months ended March 31, 2010, 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 2009
comparative income tax reconciliation has 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 three months ended March 31,
2009.
|
12
As
at
|
||||||||
(Thousands
of U.S. Dollars)
|
March
31, 2010
|
December
31, 2009
|
||||||
Deferred
Tax Assets
|
||||||||
Tax
benefit of loss carryforwards
|
$ | 21,828 | $ | 22,318 | ||||
Tax
basis in excess of book value
|
3,150 | 1,691 | ||||||
Foreign
tax credits and other accruals
|
15,674 | 15,508 | ||||||
Capital
losses
|
1,645 | 1,481 | ||||||
Deferred
tax assets before valuation allowance
|
42,297 | 40,998 | ||||||
Valuation
allowance
|
(31,083 | ) | (29,528 | ) | ||||
$ | 11,214 | $ | 11,470 | |||||
Deferred
tax assets - current
|
$ | 4,311 | $ | 4,252 | ||||
Deferred
tax assets - long-term
|
6,903 | 7,218 | ||||||
11,214 | 11,470 | |||||||
Deferred
Tax Liabilities
|
||||||||
Long-term
- book value in excess of tax basis
|
(218,981 | ) | (216,625 | ) | ||||
Net
Deferred Tax Liabilities
|
$ | (207,767 | ) | $ | (205,155 | ) |
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 March 31, 2010
was $0.9 million (December 31, 2009 - $0.9 million).
As at
March 31, 2010, the Company has deferred tax assets relating to net operating
loss carryforwards of $21.8 million (December 31, 2009 - $22.3 million) and
capital losses of $1.6 million (December 31, 2009 - $1.5 million) before
valuation allowances. Of these losses, $16.9 million (December 31, 2008 - $18.2
million) are losses generated by the foreign subsidiaries of the Company. Of the
total losses, $0.1 million (December 31, 2009 - $0.1 million) will begin to
expire by 2011 and $23.4 million of net operating losses (December 31, 2009 -
$23.7 million) will begin to expire thereafter.
13
8. Accounts Payable and Accrued
Liabilities
The
balances in accounts payable and accrued liabilities and are comprised of the
following:
As
at March 31, 2010
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant and equipment
|
$ | 15,994 | $ | 231 | $ | 689 | $ | 16,914 | ||||||||
Payroll
|
2,005 | 149 | 799 | 2,953 | ||||||||||||
Audit,
legal, and consultants
|
- | - | 1,212 | 1,212 | ||||||||||||
General
and administrative
|
3,340 | 240 | 208 | 3,788 | ||||||||||||
Operating
|
31,295 | 1,191 | - | 32,486 | ||||||||||||
Total
|
$ | 52,634 | $ | 1,811 | $ | 2,908 | $ | 57,353 | ||||||||
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, and 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 |
9. Commitments and
Contingencies
Leases
Gran
Tierra holds three categories of operating leases: office, vehicle and housing.
The Company pays monthly amounts of $173,000 for office leases, $12,000 for
vehicle leases and $6,000 for certain employee accommodation leases in Colombia,
Argentina, Peru, and Brazil. Future lease payments at March 31, 2010 are as
follows:
As
at March 31, 2010
|
||||||||||||||||||||
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
|
$ | 6,424 | $ | 2,278 | $ | 2,917 | $ | 1,229 | $ | - | ||||||||||
Software
and telecommunication
|
1,610 | 1,083 | 527 | - | - | |||||||||||||||
Drilling,
completion, facility construction and oil transportation
services
|
44,386 | 43,828 | 558 | - | - | |||||||||||||||
Total
|
$ | 52,420 | $ | 47,189 | $ | 4,002 | $ | 1,229 | $ | - |
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.
14
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 $5.4
million.
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.
10.
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 March
31, 2010, 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.
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 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 $110,000 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. For the three months ended March 31, 2010, the Company had one
significant customer for its Colombian crude oil, Ecopetrol. 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. The Company currently does not have any
financial derivatives. Previously, none of the Company's derivative instruments
qualified as fair value hedges or cash flow hedges, and accordingly, changes in
fair value of the derivative instruments were recognized as income or
expense in the consolidated statement of operations and retained earnings with a
corresponding adjustment to the fair value of derivative instruments recorded on
the balance sheet.
11.
Related Party Transaction
On
February 1, 2009, the Company entered into a sublease for office space
with a company (“sublessee”), of which two of Gran Tierra’s directors are
shareholders and directors and one such director is an officer of the
sublessee. The term of the sublease runs from February 1, 2009 to August
31, 2011 and the sublease payment is $8,000 per month plus approximately $4,600
for operating and other expenses. The terms of the sublease were
consistent with market conditions in the Calgary, Alberta, Canada real
estate market.
15
ITEM 2. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Statement Regarding Forward-Looking
Information
This report contains forward-looking
statements within the meaning of Section 27A of the United States
Securities Act of 1933, as amended, Section 21E of the Securities Exchange
Act of 1934 and the Private Securities Litigation Reform Act of 1995. All
statements other than statements of historical facts included in this Quarterly
Report on Form 10-Q, including without limitation, statements in this
Management’s Discussion and Analysis of Financial Condition and Results of
Operations regarding our projected financial position and results, estimated
quantities and net present values of reserves, business strategy, plans and
objectives of our management for future operations, covenant compliance 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 nor can we assure adequate funding will be
available to execute our planned future capital program. 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 II, Item 1A
“Risk Factors” in this Quarterly Report on Form 10-Q. 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 Quarterly Report on Form 10-Q 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.
The
following discussion of our financial condition and results of operations should
be read in conjunction with the Financial Statements as set out in Part I – Item
1 of this Quarterly Report on Form 10-Q, as well as the financial statements and
Management’s Discussion and Analysis of Financial Condition and Results of
Operations included in our Annual Report on Form 10-K, filed with the U.S.
Securities and Exchange Commission on February 26, 2010.
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.
16
Financial
and Operational Highlights
(Thousands
of U.S. Dollars, Except Per Share Amounts)
Three
Months Ended March 31,
|
||||||||||||
2010
|
2009
|
%
Change
|
||||||||||
Production
- Barrels of Oil Equivalent per Day
|
14,949 | 10,480 | 43 | |||||||||
Prices
Realized - Per Barrel of Oil Equivalent
|
$ | 69.07 | $ | 35.15 | 97 | |||||||
Revenue
and Other Income ($000's)
|
$ | 93,110 | $ | 33,565 | 177 | |||||||
Net
Income ($000's)
|
$ | 9,960 | $ | 14,132 | (30 | ) | ||||||
Net
Income Per Share - Basic
|
$ | 0.04 | $ | 0.06 | (33 | ) | ||||||
Net
Income Per Share - Diluted
|
$ | 0.04 | $ | 0.06 | (33 | ) | ||||||
Funds
Flow From Operations (1)
|
$ | 54,274 | $ | 20,593 | 164 | |||||||
Capital
Expenditures ($000's)
|
$ | 19,504 | $ | 19,166 | 2 |
(1) Gran
Tierra has disclosed a non-GAAP measure “funds flow from operations” which does
not have any standardized meaning prescribed under GAAP. Management uses this
financial measure to analyze operating performance and the income (loss)
generated by Gran Tierra’s principal business activities prior to the
consideration of how non-cash items affect that income, and believes that this
financial measure is also useful supplemental information for investors to
analyze operating performance and Gran Tierra’s financial results. Investors
should be cautioned that this measure should not be construed as an alternative
to net income (loss) or other measures of financial performance as determined in
accordance with GAAP. Gran Tierra’s method of calculating this measure may
differ from other companies and, accordingly, it may not be comparable to
similar measures used by other companies. Funds flow from operations, as
presented, is net income (loss) adjusted for depletion, depreciation and
accretion, deferred taxes, stock based compensation, unrealized loss (gain) on
financial instruments and unrealized foreign exchange losses
(gains).
Three
Months Ended March 31,
|
||||||||
Funds
Flow From Operations - Non-GAAP Measure
|
2010
|
2009
|
||||||
Net
income
|
$ | 9,960 | $ | 14,132 | ||||
Adjustments
to reconcile net income to funds flow from operations
|
||||||||
Depletion,
depreciation, accretion, and impairment
|
40,343 | 27,529 | ||||||
Deferred
taxes
|
(10,054 | ) | (3,982 | ) | ||||
Stock-based
compensation
|
1,362 | 1,125 | ||||||
Unrealized
(gain) loss on financial instruments
|
(44 | ) | 87 | |||||
Unrealized
foreign exchange loss (gain)
|
12,707 | (18,298 | ) | |||||
Funds
Flows From Operations
|
$ | 54,274 | $ | 20,593 |
As at
|
||||||||||||
March
31, 2010
|
December
31, 2009
|
%
Change
|
||||||||||
Cash
& Cash Equivalents ($000's)
|
$ | 265,676 | $ | 270,786 | (2 | ) | ||||||
Working
Capital (including cash & cash equivalents) ($000's)
|
$ | 267,014 | $ | 215,161 | 24 | |||||||
Property,
Plant & Equipment ($000's)
|
$ | 692,656 | $ | 712,743 | (3 | ) |
17
·
|
In
the first quarter of 2010, oil and gas production (net after royalty and
inventory adjustments) averaged 14,949 barrels of oil equivalent per day
(“BOEPD”), an increase of 43% over the same period in 2009, due mainly to
production of crude oil from three new development wells in the Costayaco
field in the Chaza Block in Colombia where Gran Tierra has a 100% working
interest.
|
·
|
Revenue
and other income increased by 177% over the same period in 2009 due to
increased production and higher oil
prices.
|
·
|
Net
income of $10.0 million or $0.04 per share basic and diluted, compared to
net income of $14.1 million or $0.06 per share basic and diluted in 2009.
Net income was impacted by a foreign exchange loss, of which $12.7 million
is an unrealized non-cash foreign exchange loss, resulting from the
translation of a deferred tax liability recorded on the purchase of
Solana. The deferred tax liability is denominated in Colombian pesos and
the devaluation of 6% in the U.S. dollar against the Colombian Peso in the
current quarter resulted in the foreign exchange
loss.
|
·
|
Funds
flow from operations for the three months ended March 31, 2010 increased
164% over the same quarter in the prior year primarily as a result of
increased production from three additional development wells drilled in
Colombia and a 96% improvement in the oil price received for that
production.
|
·
|
Oil
and gas property expenditures for the first quarter of 2010 include the
successful drilling of the Juanambu – 2 well in the Guayuyaco block, in
addition to facility construction and drilling site preparations in the
Costayaco block.
|
·
|
Our
cash and cash equivalents position of $265.7 million at March 31, 2010
decreased from $270.8 million at December 31, 2009 as a result of
year-to-date capital expenditures, partially offset by cash provided by
operating activities and proceeds from the issue of shares on the exercise
of stock options and warrants.
|
·
|
Working
capital (including cash and cash equivalents) was $267.0 million at March
31, 2010, which is a $51.9 million increase from December 31, 2009, due
mainly to the increase in accounts receivable from year end. Accounts
receivable at any period end other than year end include two months of oil
sales in Colombia. Year end accounts receivable, traditionally include
less than one month of oil sales as our purchaser prefers to settle all
other outstanding amounts.
|
·
|
Property,
plant and equipment as at March 31, 2010 was $692.7 million, a decrease
from December 31, 2009, primarily as a result of depletion,
depreciation and accretion (“DD&A”), partially offset by capital
additions.
|
Operational Highlights for
the Three Months Ended March 31, 2010
·
|
Successful Production
Testing of Juanambu - 2
In
February 2010, we completed logging operations of the Juanambu - 2
development well in the Juanambu field discovered in 2007 in the Guayuyaco
Block in Colombia. Testing of the well was completed early in
March 2010 and the well came on production later in the
month.
|
·
|
Moqueta - 1 Civil Work
Completed
Location
construction for the Moqueta - 1 exploration well in the Chaza Block
in Colombia, approximately 5 kilometers north of the Costayaco field, was
mostly completed by the end of March 2010. Drilling of the well is
expected to begin in May 2010.
|
·
|
Costayaco - 11 Civil
Work Commenced
In
March 2010, we commenced civil work for the Costayaco - 11 injector well
in the Chaza Block in Colombia. Drilling of the well is expected to begin
in May 2010.
|
·
|
Dantayaco
-1 Exploration Well
Drilling
was completed on the Dantayaco - 1 exploration well in the Chaza Block, in
the Putumayo basin of Colombia, at the end of 2009. During testing, only
formation water was recovered and the well was plugged and abandoned on
January 3, 2010.
|
·
|
Environmental Impact
Assessment (“EIA”) Approval in Peru
The
EIA approval for seismic and drilling operations has been approved for
Block 128, Marañon Basin, Peru. Amendments to this approval are being
reviewed. Seismic crew mobilization is planned for the second quarter,
with drilling of up to four wells in Peru expected to commence in the
third quarter, and continue through the fourth quarter, of
2010.
|
18
Consolidated Results of
Operations
Three
Months Ended March 31,
|
||||||||||||
Consolidated
Results of Operations
|
2010
|
2009
|
%
Change
|
|||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||
Oil
and natural gas sales
|
$ | 92,932 | $ | 33,151 | 180 | |||||||
Interest
|
178 | 414 | (57 | ) | ||||||||
93,110 | 33,565 | 177 | ||||||||||
Operating
expenses
|
10,185 | 7,086 | 44 | |||||||||
Depletion,
depreciation, accretion, and impairment
|
40,343 | 27,529 | 47 | |||||||||
General
and administrative expenses
|
7,190 | 5,125 | 40 | |||||||||
Foreign
exchange loss (gain)
|
14,294 | (20,222 | ) | 171 | ||||||||
Derivative
financial instruments gain
|
(44 | ) | - | - | ||||||||
71,968 | 19,518 | 269 | ||||||||||
Income
before income taxes
|
21,142 | 14,047 | 51 | |||||||||
Income
tax (expense) recovery
|
(11,182 | ) | 85 | (13,255 | ) | |||||||
Net
income
|
$ | 9,960 | $ | 14,132 | (30 | ) | ||||||
Production,
Net of Royalties
|
||||||||||||
Oil
and NGL's ("bbl") (1)
|
1,341,682 | 935,048 | 43 | |||||||||
Natural
gas ("mcf") (1)
|
22,518 | 49,028 | (54 | ) | ||||||||
Total
production ("boe") (1) (2)
|
1,345,435 | 943,219 | 43 | |||||||||
Average
Prices
|
||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 69.20 | $ | 35.27 | 96 | |||||||
Natural
gas ("per mcf")
|
$ | 3.90 | $ | 3.48 | 12 | |||||||
Consolidated
Results of Operations ("per boe")
|
||||||||||||
Oil
and natural gas sales
|
$ | 69.07 | $ | 35.15 | 97 | |||||||
Interest
|
0.13 | 0.44 | (70 | ) | ||||||||
69.20 | 35.59 | 94 | ||||||||||
Operating
expenses
|
7.57 | 7.51 | 1 | |||||||||
Depletion,
depreciation, accretion, and impairment
|
29.99 | 29.19 | 3 | |||||||||
General
and administrative expenses
|
5.34 | 5.43 | (2 | ) | ||||||||
Foreign
exchange loss (gain)
|
10.62 | (21.44 | ) | 150 | ||||||||
Derivative
financial instruments gain
|
(0.03 | ) | - | - | ||||||||
53.49 | 20.69 | 158 | ||||||||||
Income
before income taxes
|
15.71 | 14.90 | 5 | |||||||||
Income
tax (expense) recovery
|
(8.31 | ) | 0.09 | (9,333 | ) | |||||||
Net
income
|
$ | 7.40 | $ | 14.99 | 51 |
(1) 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 is not necessarily indicative of
the relationship of oil and gas prices. At December 31, 2009, 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 2009 boe volumes presented have increased by 5,720 boe
from those volumes previously disclosed. Natural gas liquids (“NGL”) volumes are
converted to boe on a one-to-one basis with oil.
(2)
Production represents production volumes adjusted for inventory
changes.
19
Consolidated Results of Operations for the Three Months Ended
March 31,
2010 Compared to the
Results for the Three Months Ended March 31, 2009
Net
income of $10.0 million, or $0.04 per share basic and diluted, was recorded for
the three months ended March 31, 2010 compared to net income of $14.1 million,
or $0.06 per share basic and diluted, for the same period in 2009. Higher oil
revenues due to increased production and higher prices, more than offset
increased operating, DD&A, and general and administrative expenses
(“G&A”) for the current quarter. Net income for the first quarter of 2010
included a foreign exchange loss of $14.3 million, of which $12.7 million is an
unrealized non-cash foreign exchange loss. Net income for the first quarter of
2009 included a $20.2 million foreign exchange gain, of which $18.3 million was
an unrealized non-cash foreign exchange gain.
Crude oil and NGL
production, net after royalties, for the three months ended March 31,
2010 increased to 1,341,682 barrels compared to 935,048 barrels for the same
period in 2009 due mainly to increased production from our Colombia operations.
Average realized crude oil prices for the current quarter increased to $69.20
per barrel from $35.27 per barrel for the first three months of 2009 reflecting
higher West Texas Intermediate (“WTI”) oil prices.
Revenue and
interest
increased 177% to $93.1 million for the three months ended March 31, 2010
compared to $33.6 million in the same period in 2009 due to an increase of
43% in crude oil production, mainly due to three new development wells in the
Costayaco field, and increased crude oil prices.
Operating
expenses for the first quarter of 2010 amounted to $10.2 million, a
44% increase from the same period in 2009 due to expanded operations and
increased production levels in Colombia. For the three months ended March
31, 2010, operating expenses on a boe basis were $7.57 per boe, a slight
increase over the same period in 2009.
DD&A expense
for the current quarter increased to $40.3 million compared to $27.5 million for
the same quarter in 2009 due to increased production levels and a $3.7 million
ceiling test impairment loss in our Argentina cost center. On a boe basis,
DD&A for the three months ended March 31, 2010 was $29.99 compared to $29.19
for the same period in 2009.
G&A expenses
of $7.2 million for the three months ended March 31, 2010, were 40% higher than
the same period in 2009 primarily due to increased employee related costs
reflecting the expanded operations in Colombia. However, due to higher
production in 2010, G&A expenses per boe decreased 2% to $5.34 per boe for
the current quarter, compared to $5.43 per boe for the first quarter of
2009.
The foreign
exchange loss
of $14.3 million, of which $12.7 million is an unrealized non-cash
foreign exchange loss, for the first quarter of 2010 primarily represents a
foreign exchange loss resulting from the translation of a deferred tax liability
recorded on the purchase of Solana. In the first quarter of 2009, a $20.2
million foreign exchange gain was recorded, of which $18.3 million was an
unrealized non-cash foreign exchange gain, primarily as a result of the
translation of the Solana deferred tax liability. The deferred tax liability is
denominated in Colombian pesos and the devaluation of 6% in the U.S. dollar
against the Colombian Peso in the current quarter resulted in the foreign
exchange loss. This compares to a 14% appreciation in the U.S. dollar against
the Colombian Peso for the three months ended March 31, 2009 which resulted in
the foreign exchange gain recorded in that period.
Income tax
expense for the three months ended March 31, 2010 amounted to $11.2
million compared to an income tax recovery of $0.1 million recorded in the same
period in 2009. The increase of $11.3 million in income tax expense over the
same period in 2009 is primarily due to higher income before income taxes from
increased oil prices received and higher production over the same period in the
prior year as previously discussed. The effective tax rate to March 31, 2010 is
53% and has increased from the same period in 2009 primarily due to the increase
in the foreign translation losses that are neither taxable nor deductible for
tax purposes in each of the respective jurisdictions. The variance from the 35%
U.S. statutory rate for the first quarter of 2010 results from non-deductible
foreign currency translation losses as described above and an increase in
valuation allowances taken on losses incurred in the U.S., Canada, Peru and
Brazil, offset by enhanced tax depreciation taken on oil and gas capital
expenditures. The variance from the 35% U.S. statutory rate for the first
quarter of 2009 is primarily attributable to foreign translation gains that are
not taxable for tax purposes in each of the respective jurisdictions recognition
and valuation allowances taken on losses incurred in the U.S., Canada, and
Peru.
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. For the three months ended March 31,
2010, Colombia generated 96% of our revenue and other income.
20
Segmented
Results – Colombia
Three
Months Ended March 31,
|
||||||||||||
Segmented
Results of Operations – Colombia
|
2010
|
2009
|
%
Change
|
|||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||
Oil
and natural gas sales
|
$ | 89,433 | $ | 30,275 | 195 | |||||||
Interest
|
77 | 224 | (66 | ) | ||||||||
89,510 | 30,499 | 193 | ||||||||||
Operating
expenses
|
8,102 | 6,098 | 33 | |||||||||
Depletion,
depreciation and accretion
|
35,006 | 25,923 | 35 | |||||||||
General
and administrative expenses
|
3,072 | 1,607 | 91 | |||||||||
Foreign
exchange loss (gain)
|
14,570 | (20,710 | ) | 170 | ||||||||
60,750 | 12,918 | 370 | ||||||||||
Segment
income before income taxes
|
$ | 28,760 | $ | 17,581 | 64 | |||||||
Production,
Net of Royalties
|
||||||||||||
Oil
and NGL's ("bbl") (1)
|
1,265,569 | 851,271 | 49 | |||||||||
Natural
gas ("mcf") (1)
|
22,518 | 49,028 | (54 | ) | ||||||||
Total
production ("boe") (1) (2)
|
1,269,322 | 859,442 | 48 | |||||||||
Average
Prices
|
||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 70.60 | $ | 35.36 | 100 | |||||||
Natural
gas ("per mcf")
|
$ | 4.02 | $ | 3.48 | 16 | |||||||
Segmented
Results of Operations ("per boe")
|
||||||||||||
Oil
and natural gas sales
|
$ | 70.46 | $ | 35.23 | 100 | |||||||
Interest
|
0.06 | 0.26 | (77 | ) | ||||||||
70.52 | 35.49 | 99 | ||||||||||
Operating
expenses
|
6.38 | 7.10 | (10 | ) | ||||||||
Depletion,
depreciation and accretion
|
27.58 | 30.16 | (9 | ) | ||||||||
General
and administrative expenses
|
2.42 | 1.87 | 29 | |||||||||
Foreign
exchange loss (gain)
|
11.48 | (24.10 | ) | 148 | ||||||||
47.86 | 15.03 | 218 | ||||||||||
Segment
income before income taxes
|
$ | 22.66 | $ | 20.46 | 11 |
(1)
|
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 is not necessarily indicative of
the relationship of oil and gas prices. At December 31, 2009, 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 2009 boe volumes presented
have increased by 5,720 boe from those volumes previously disclosed.
Natural gas liquids (“NGL”) volumes are converted to boe on a one-to-one
basis with oil.
|
(2)
|
Production
represents production volumes adjusted for inventory
changes.
|
21
Segmented
Results of Operations – Colombia for the Three Months Ended March 31, 2010
Compared to the Results for the Three Months Ended March 31, 2009
For the
three months ended March 31, 2010, income before
income taxes from Colombia amounted to $28.8 million compared to
income before taxes of $17.6 million recorded for the same period in 2009. This
is mainly the result of higher oil revenues due to increased oil
production and higher oil prices. These factors were partially offset by higher
operating expenses due to increased Colombian production and increased general
and administrative expenses from expanded activities. Additionally, in the
current quarter, a $14.6 million foreign exchange loss, of which $12.6 million
is an unrealized non-cash foreign exchange loss, primarily due to the
translation of deferred taxes, and a $9.1 million increase in DD&A also
partially offset higher revenues in the period. On a per barrel basis, the
pre-tax income for the three months ended March 31, 2010 was $22.66 versus
$20.46 recorded for the same period in 2009. The difference is due to the same
factors listed above.
For the
three months ended March 31, 2010, production of
crude oil and NGLs, net after royalties, increased by 49% to 1,265,569
barrels compared to 851,271 barrels for the same period in 2009. This increase
is mostly due to the production from three new development wells in the
Costayaco field. These production levels are after government royalties ranging
from 8% to 26% and third party royalties of 2% to 10%.
Gran
Tierra’s Colombian operating results for the three months ended March 31, 2010
are principally impacted by the inclusion of production from three new
development wells (Costayaco – 8, – 9, and –10) in the Costayaco field and
Juanambu – 2 in the Guayuyaco Block. In the first quarter of 2009, Colombia
production included production from Costayaco – 1, – 2, – 3, – 4, – 5 and
Juanambu – 1 along with production from the Santana Block.
Our
production in the first quarter of 2009 was impacted by political and
economic factors in Colombia. 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
following 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 during the first 10 days of January.
Revenue and
interest increased 193% in 2010 compared to 2009 due to an increase
in net realized crude oil prices and increased production. The average net
realized prices for crude oil, which are based on WTI prices, increased by 100%
to $70.60 per barrel for the three months ended March 31, 2010 compared to the
same period last year.
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 Costayaco crude oil is $32.13 for 2010. 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 $80 WTI per barrel are approximately 25.7%, including the
additional government royalty of approximately 18.0%. 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.
Operating
expenses for the three months ended March 31, 2010 increased to $8.1
million from $6.1 million in the same period last year. The increased operating
expenses resulted from the increase in production at Costayaco. However, on a
per barrel basis, operating expenses for the first quarter of 2010 declined to
$6.38 compared to $7.10 incurred for the same period last year, reflecting the
reduction of fixed operating costs per barrel as total production
increased.
For the
three months ended March 31, 2010, DD&A
expense increased to $35.0 million compared to from $25.9 million in the same
period in 2009. Increased production levels coupled with a higher depletable
cost base partially offset by higher crude oil proved reserves, accounted for
the increase in DD&A expense. On a per boe basis, the DD&A expense
in Colombia decreased by 9% to $27.58 for the first three months of 2010
compared with the comparable period last year due to the higher proved
reserves.
An
increased level of development and operating activities and higher stock-based
compensation expense resulted in G&A
expense increasing to $3.1 million for the three months ended March 31, 2010
from $1.6 million incurred for the same period in 2009. On a per barrel basis,
G&A expense increased by 29% to $2.42 from $1.87 for the first quarter of
2010 compared with the same period in 2009.
For the
three months ended March 31, 2010, the foreign exchange
loss of $14.6 million, of which $12.6 million is an unrealized non-cash
foreign exchange loss (first quarter of 2009 - $20.7 million gain, of which
$18.5 million was an unrealized gain) 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 $110,000 for each one
peso decrease in the exchange rate of the Colombian peso to one US
dollar.
Capital
Program - Colombia
Gran
Tierra’s focus in Colombia for the first quarter of 2010 was preparation for the
2010 exploration drilling program, drilling of the Juanambu -2 development well
in the Guayayaco field, and continuation of development of the Costayaco field.
In support of this strategy, our capital expenditures in Colombia amounted to
$17.6 million for the three months ended March 31, 2010.
22
Segmented
Capital Expenditures – Colombia
|
Three
Months Ended,
|
|||
Block
and Activity
|
March
31, 2010
|
|||
(Millions
of U.S. Dollars)
|
||||
Chaza
|
Costayaco
facilities and site preparation for Costayaco -11 and Moqueta -1
drilling
|
$
|
7.2
|
|
Guayayaco
|
Juanambu
-2 drilling and facilities
|
4.8
|
||
Rumiyaco
|
Commencement
of 3D seismic
|
2.3
|
||
Garibay
|
Completion
of 3D seismic program
|
0.6
|
||
Piedemonte
Sur
|
Rig
mobilization for Taruka -1 well
|
0.6
|
||
Capitalized
G&A and other
|
2.1
|
|||
Segmented
Capital Expenditures – Colombia
|
$
|
17.6
|
For
comparison, during the three months ended March 31, 2009, we spent $17.9 million
on capital projects.
Segmented
Capital Expenditures - Colombia
|
Three
Months Ended,
|
|||
Block
and Activity
|
March
31, 2009
|
|||
(Millions
of U.S. Dollars)
|
||||
Chaza
|
Drilled
and tested Costayaco -7, completed testing of Costayaco -6, additional
facilities and equipment
|
$
|
8.2
|
|
Guachiria
Sur
|
Acquired
115 km2 of 3D seismic
|
3.3
|
||
Guachiria
Norte
|
Drilled
an exploration well, Puinaves-2, which was dry
|
2.2
|
||
Garibay
|
Commenced
acquisition of 110 km2 of 3D seismic
|
1.5
|
||
Rio
Magdalena
|
Commenced
long-term testing of Popa-2 well
|
0.9
|
||
Capitalized
G&A and other
|
1.8
|
|||
Segmented
Capital Expenditures – Colombia
|
$
|
17.9
|
Segmented
Results – Argentina
Three
Months Ended March 31,
|
||||||||||||
Segmented
Results of Operations - Argentina
|
2010
|
2009
|
%
Change
|
|||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||
Oil
and natural gas sales
|
$ | 3,499 | $ | 2,876 | 22 | |||||||
Interest
|
16 | 40 | (60 | ) | ||||||||
3,515 | 2,916 | 21 | ||||||||||
Operating
expenses
|
2,029 | 954 | 113 | |||||||||
Depletion,
depreciation and accretion
|
1,567 | 1,530 | 2 | |||||||||
Impairment
of carrying value of oil and natural gas properties
|
3,700 | - | - | |||||||||
General
and administrative expenses
|
720 | 527 | 37 | |||||||||
Foreign
exchange loss
|
143 | 351 | (59 | ) | ||||||||
8,159 | 3,362 | 143 | ||||||||||
Segment
loss before income taxes
|
$ | (4,644 | ) | $ | (446 | ) | 941 | |||||
Production,
Net of Royalties
|
||||||||||||
Oil
and NGL's ("bbl") (1) (2)
|
76,113 | 83,777 | (9 | ) | ||||||||
Average
Prices
|
||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 45.97 | $ | 34.33 | 34 | |||||||
Segmented
Results of Operations ("per boe")
|
||||||||||||
Oil
and natural gas sales
|
$ | 45.97 | $ | 34.33 | 34 | |||||||
Interest
|
0.21 | 0.48 | (56 | ) | ||||||||
46.18 | 34.81 | 33 | ||||||||||
Operating
expenses
|
26.66 | 11.39 | 134 | |||||||||
Depletion,
depreciation and accretion
|
20.59 | 18.26 | 13 | |||||||||
Impairment
of carrying value of oil and natural gas properties
|
48.61 | - | - | |||||||||
General
and administrative expenses
|
9.46 | 6.29 | 50 | |||||||||
Foreign
exchange loss
|
1.88 | 4.19 | (55 | ) | ||||||||
107.20 | 40.13 | 167 | ||||||||||
Segment
loss before income taxes
|
$ | (61.02 | ) | $ | (5.32 | ) | 1,047 |
(1)
NGL volumes are converted to boe on a one-to-one basis with
oil.
|
(2)
Production represents production volumes adjusted for inventory
changes.
|
23
Segmented
Results of Operations – Argentina for the Three Months Ended March 31, 2010
Compared to the Results for the Three Months Ended March 31, 2009
For the
three months ended March 31, 2010 the pre-tax loss
from Argentina was $4.6 million compared to a pre-tax loss of $0.4
million recorded in the same period in 2009. The increased loss resulted from
lower production levels, increased operating costs, DD&A and a $3.7 million
ceiling test impairment loss, offset partially by increased prices.
Crude oil and NGL
production, net after 12% royalties, decreased to 76,113 barrels for the
three months ended March 31, 2010 compared to 83,777 barrels for the same period
in 2009. The decrease resulted from increased workover related well downtime
compared to the prior year.
Due to
the local regulatory regimes, the price we currently receive for production from
our blocks is approximately $47 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 March 31,
2010. We are working with other oil and gas producers in the area, as well
as Refiner S.A. and provincial governments, to lobby the federal government for
change.
With a
34% improvement in regulated crude oil prices, partially offset by lower
production levels, our
revenues have increased by 22% to $3.5 million in the three months
ended March 31, 2010 compared to $2.9 million for the same period in
2009.
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. 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. 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.
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 three months ended March 31, 2010, increased to $2.0
million ($26.66 per boe) compared to $1.0 million ($11.39 per boe) incurred in
the same quarter last year due to increased workovers in the current period.
Lower production volumes and increased workovers in the current period resulted
in the increase in operating costs on a per boe basis.
DD&A
expense for the three months ended March 31, 2010 was $1.6 million, an increase
from the $1.5 million recorded in the same period of 2009. On a per boe basis,
DD&A for the three months ended March 31, 2010 increased to $20.59 from
$18.26 recorded in the same period last year. The impact of lower
proved reserves more than offset a decreasing proved depletable cost base. This
decreasing proved depletable cost base is a result of reduced new development
expenditures in Argentina. In addition, for the three months ended March 31,
2010, Gran Tierra recorded a $3.7 million ceiling test impairment loss in our
Argentina cost center.
Capital
Program - Argentina
Capital
expenditures for the three months ended March 31, 2010, amounted to $0.7 million
mainly relating to facility construction, and the acquisition of seismic data.
Capital expenditures in Argentina for the three months ended March 31, 2009,
were $0.4 million. These costs included facilities upgrade costs in the Palmar
Largo area, exploration land lease costs and capitalized G&A including
non-cash stock based compensation expense.
24
Segmented
Results – Corporate
Three
Months Ended March 31,
|
||||||||||||
2010
|
2009
|
%
Change
|
||||||||||
Segmented
Results of Operations - Corporate
|
||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||
Interest
|
$ | 85 | $ | 150 | (43 | ) | ||||||
Operating
expenses
|
54 | 34 | 59 | |||||||||
Depletion,
depreciation and accretion
|
70 | 76 | (8 | ) | ||||||||
General
and administrative expenses
|
3,398 | 2,991 | 14 | |||||||||
Derivative
financial instruments gain
|
(44 | ) | - | - | ||||||||
Foreign
exchange (gain) loss
|
(419 | ) | 137 | (406 | ) | |||||||
3,059 | 3,238 | (6 | ) | |||||||||
Segment
loss before income taxes
|
$ | (2,974 | ) | $ | (3,088 | ) | (4 | ) |
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 securities regulations, the results of the Corporate Segment include the
results of our initial operations in Peru and Brazil.
G&A
Expenses
The
increase in G&A expenses over the same period in the prior year was mainly
attributable to increased staff to manage expanded operations and higher
stock-based compensation expense due to increased stock option grants associated
with increased staff.
Foreign
Exchange (Gain) Loss
The
foreign exchange (gain) loss 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 three months ended
March 31, 2010 were $1.3 million. These expenditures included expenditures of
$0.5 million for Peru on our exploration blocks 122 and 128. The expenditures
incurred mainly related to drilling feasibility and geological studies on the
blocks. For comparison, during the first quarter of 2009, capital expenditures
of $0.7 million related to drilling feasibility and geological studies on the
Peru blocks.
Liquidity
and Capital Resources
At March
31, 2010, we had cash and cash equivalents of $265.7 million compared to $270.8
million at December 31, 2009. We believe that our cash position as well
as 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.
The
costless collar we had entered into in accordance with the terms of the credit
facility with Standard Bank Plc terminated in February 2010 as a result of the
expired credit facility.
Cash
Flows
During
the three months ended March 31, 2010, our cash and cash equivalents decreased
by $5.1 million as cash inflows from operations of $2.4 million and from
financing activities of $18.2 million were more than offset by cash outflows for
investing activities of $25.7 million. Net cash provided by operating activities
was affected by the significant increase in crude oil production and increase in
prices, offset by the increases in receivables related to oil
sales.
During
the three months ended March 31, 2009, our cash and cash equivalents decreased
by $29.0 million due to cash used in operating activities of $7.6 million and
capital expenditures of $21.9 million. Net cash used in operating activities was
affected by the significant increase in crude oil production which was more
than offset by the decrease in prices as well as increases in receivables
related to oil sales.
25
Off-Balance
Sheet Arrangements
As at
March 31, 2010, we had no off-balance sheet arrangements.
Contractual
Obligations
Gran
Tierra holds three categories of operating leases, namely office, vehicle and
housing. Future lease payments and other contractual obligations at March 31,
2010 are as follows:
As
at March 31, 2010
|
||||||||||||||||||||
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
|
$ | 6,424 | $ | 2,278 | $ | 2,917 | $ | 1,229 | $ | - | ||||||||||
Software
and Telecommunication
|
1,610 | 1,083 | 527 | - | - | |||||||||||||||
Drilling,
Completion, Facility Construction and Oil Transportation
Services
|
44,386 | 43,828 | 558 | - | - | |||||||||||||||
Total
|
$ | 52,420 | $ | 47,189 | $ | 4,002 | $ | 1,229 | $ | - |
Contractual
commitments have increased $19.1 million from December 31, 2009 as a result of
entering into third party facility construction, oil transportation and drilling
rig commitment contracts in Colombia and Peru.
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 $10,200 per month and operating and other expenses
are approximately $4,600 per month. The lease expires on April 30,
2014. On February 1, 2009, we entered into a sublease for that
office space with a sublessee, of which two of Gran Tierra’s directors are
shareholders and directors and one such director is an officer of the
sublessee. The term of the sublease runs from February 1, 2009 to August
31, 2011 and the sublease payment is $8,000 per month plus approximately $4,600
for operating and other expenses. The terms of the sublease were
consistent with market conditions in the Calgary real estate
market.
Outlook
Business
Environment
Our
revenues have been significantly 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 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
current fiscal uncertainty regarding Greece and, now implicating other countries
in the European Community, is having an impact on world markets, and the company
is unable to determine the impact, if any, this may have on oil prices and
demand.
Our
future growth and acquisitions may depend on our ability to raise additional
funds through equity and debt markets. Should we be required to raise debt or
equity financing to fund capital expenditures or other acquisition and
development opportunities, such funding may be affected by the market value of
our common stock. If the price of our common stock declines, our ability to
utilize our stock to raise capital may be negatively affected. Also, raising
funds by issuing stock or other equity securities would further dilute our
existing stockholders, and this dilution would be exacerbated by a decline in
our stock price. Any securities we issue may have rights, preferences and
privileges that are senior to our existing equity securities. Borrowing money
may also involve further pledging of some or all of our assets.
26
2010
Work Program and Capital Expenditure Program
Gran
Tierra’s 2010 work program is intended to create value in our existing assets by
growing our reserves and production from drilling 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 from
exploration success or 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, we currently expect production in 2010 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 are $129 million
in Colombia, $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
Colombia capital budget for 2010 is $129 million; $37.5 million has been
allocated for facilities improvements associated with ongoing development of
existing reserves, and $92 million for seismic acquisition and exploration
drilling.
New
infrastructure construction planned for the Costayaco field includes crude
gathering lines, water lines, upgrading a pumping station, gas-fired power
plant, and storage batteries. A water handling, processing, and injection
facility for Costayaco is also planned. A water injection well in the Costayaco
field, Costayaco -11 is scheduled to begin drilling in May, 2010.
Outlook
– Argentina
Gran
Tierra is the largest exploration landholder in the Noroeste Basin of northern
Argentina. We have a working interest in seven blocks of land, six operated by
Gran Tierra, encompassing approximately 1.6 million gross acres, or 1.3 million
net acres. During the third quarter of 2010 a re-entry and sidetrack is planned
for the Valle Morado VM.x-1001 gas well at an estimated cost of $15
million. Existing pipeline and gas processing plant capacity is
capable of handling up to 35 mmcf/d (million cubic feet per day). Gran Tierra
has received confirmation from the Secretary of Energy that Valle Morado
qualifies for the “Gas Plus Program”. This allows Gran Tierra to
negotiate higher gas prices than would have been possible without the Gas Plus
qualification. Recent gas contracts signed by other gas producers have resulted
in gas prices in excess of $4.00/mmbtu (million British thermal
units). A seismic acquisition program, including approximately 188km
of 2D seismic data and 150km2 of 3D seismic data, is also planned for the Santa
Victoria block. Production in Argentina is expected to be maintained
between 800 BOPD and 1,000 BOPD, net after royalty, in 2010.
Total
2010 capital expenditures planned for Argentina is $23 million.
Outlook
– Peru
Gran
Tierra expects to begin acquiring approximately 480km of 2D seismic data in the
second quarter of 2010 over 16 principal leads amongst the 24 leads identified
on the two blocks. Stratigraphic test drilling on up to four prospects is
expected to take place in the third and fourth quarters of 2010.
Total
2010 capital expenditures planned for Peru is $41 million.
The
preparation of financial statements under 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.
27
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. Our critical accounting estimates are disclosed in
Item 7 of our 2009 Annual Report on Form 10-K, filed with the Securities and
Exchange Commission on February 26, 2010, and have not changed materially since
the filing of that document.
ITEM 3 - QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 had entered into a costless collar financial derivative contract for crude
oil based on WTI price. At December 31, 2009, this costless collar represented a
liability of $44,000. 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. As a result of the
expiration of our credit facility, this costless collar has
terminated.
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 WTI 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. Currently we 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.
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 may result 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
$110,000 for each one peso decrease in the exchange rate of the Colombian peso
to one U.S. dollar.
(a) Evaluation
of Disclosure Controls and Procedures
Disclosure
Controls and Procedures
We have
established disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). 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 March 31, 2010
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.
28
Changes
in Internal Control over Financial Reporting
During
the quarter ended on March 31, 2010, there was 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.
ITEM
4T – CONTROLS AND PROCEDURES
Not
applicable.
PART II - OTHER
INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
Ecopetrol
and Gran Tierra Colombia, the contracting parties of the Guayuyaco Association
Contract, are engaged in a dispute regarding the interpretation of the procedure
for allocation of oil produced and sold during the long term test of the
Guayuyaco-1 and Guayuyaco-2 wells. This matter was reported in our Annual Report
on Form 10-K for the year ended December 31, 2009, filed with the Securities and
Exchange Commission on February 26, 2010.
ITEM 1A. RISK
FACTORS
The risks
relating to our business and industry, as set forth in our Annual Report on
Form 10-K for the fiscal year ended December 31, 2009, filed with the
Securities and Exchange Commission on February 26, 2010, are set forth below and
are unchanged at March 31, 2010.
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.
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.
29
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, Julio
Moreira, our President of Gran Tierra Brazil, and David Hardy, our Vice
President Legal and General Counsel. 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.
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.
30
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.
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%.
31
In
addition, a foreign exchange loss of $14.3 million, of which
$12.7 million is an unrealized non-cash foreign exchange loss, was
recorded in the first three months of 2010 primarily due to the translation of a
deferred tax liability recorded on the purchase of Solana. The deferred tax
liability is denominated in Colombian pesos and the devaluation of 6% in the US
dollar against the Colombian Peso in the first three months of 2010 resulted in
the foreign exchange loss.
Exchange Controls
and New Taxes Could Materially Affect our Ability to Fund Our Operations and
Realize Profits from Our Foreign
Operations.
Foreign
operations may require funding if their cash requirements exceed operating cash
flow. To the extent that funding is required, there may be exchange controls
limiting such funding or adverse tax consequences associated with such funding.
In addition, taxes and exchange controls may affect the dividends that we
receive from foreign subsidiaries.
Exchange
controls may prevent us from transferring funds abroad. For example, the
Argentine government has imposed a number of monetary and currency exchange
control measures that include restrictions on the free disposition of funds
deposited with banks and tight restrictions on transferring funds abroad, with
certain exceptions for transfers related to foreign trade and other authorized
transactions approved by the Argentine Central Bank. The Central Bank may
require prior authorization and may or may not grant such authorization for our
Argentine subsidiaries to make dividend payments to us and there may be a tax
imposed with respect to the expatriation of the proceeds from our foreign
subsidiaries.
Competition in
Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our
Production May Impair Our Business.
The oil
and gas industry is highly competitive. Other oil and gas companies will compete
with us by bidding for exploration and production licenses and other properties
and services we will need to operate our business in the countries in which we
expect to operate. Additionally, other companies engaged in our line of business
may compete with us from time to time in obtaining capital from investors.
Competitors include larger, foreign owned companies, which, in particular, may
have access to greater resources than us, may be more successful in the
recruitment and retention of qualified employees and may conduct their own
refining and petroleum marketing operations, which may give them a competitive
advantage. In addition, actual or potential competitors may be strengthened
through the acquisition of additional assets and interests. In the event that we
do not succeed in negotiating additional property acquisitions, our future
prospects will likely be substantially limited, and our financial condition and
results of operations may deteriorate.
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.
32
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:
·
|
all
bilateral aid, except anti-narcotics and humanitarian aid, would be
suspended;
|
·
|
the
Export-Import Bank of the United States and the Overseas Private
Investment Corporation would not approve financing for new projects in
Colombia;
|
·
|
United
States representatives at multilateral lending institutions would be
required to vote against all loan requests from Colombia, although such
votes would not constitute vetoes;
and
|
·
|
the
President of the United States and Congress would retain the right to
apply future trade sanctions.
|
Each of
these consequences could result in adverse economic consequences in Colombia and
could further heighten the political and economic risks associated with our
operations there. Any changes in the holders of significant government offices
could have adverse consequences on our relationship with ANH and Ecopetrol and
the Colombian government’s ability to control guerrilla activities and could
exacerbate the factors relating to our foreign operations. Any sanctions imposed
on Colombia by the United States government could threaten our ability to obtain
necessary financing to develop the Colombian properties or cause Colombia to
retaliate against us, including by nationalizing our Colombian assets.
Accordingly, the imposition of the foregoing economic and trade sanctions on
Colombia would likely result in a substantial loss and a decrease in the price
of our common stock. The United States may impose sanctions on Colombia in the
future, and we cannot predict the effect in Colombia that these sanctions might
cause.
We May Be Unable
to Obtain Additional Capital That We Will Require to Implement Our Business
Plan, Which Could Restrict Our Ability to
Grow.
We expect
that our existing cash resources will be sufficient to fund our currently
planned activities. We may require additional capital to expand our exploration
and development programs to additional properties. We may be unable to obtain
additional capital required.
When we
require additional capital we plan to pursue sources of capital through various
financing transactions or arrangements, including joint venturing of projects,
debt financing, equity financing or other means. We may not be successful in
locating suitable financing transactions in the time period required or at all,
and we may not obtain the capital we require by other means. 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.
33
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:
·
|
expand
our systems effectively or efficiently or in a timely
manner;
|
·
|
allocate
our human resources optimally;
|
·
|
identify
and hire qualified employees or retain valued employees;
or
|
·
|
incorporate
effectively the components of any business that we may acquire in our
effort to achieve growth.
|
If we are
unable to manage our growth and our operations our financial results could be
adversely affected by inefficiencies, which could diminish our
profitability.
Risks
Related to Our Industry
Unless We are
Able to Replace Our Reserves, and Develop Oil and Gas Reserves on an
Economically Viable Basis, Our Reserves, Production and Cash Flows May Decline
as a Result.
Our
future success depends on our ability to find, develop and acquire additional
oil and gas reserves that are economically recoverable. Without successful
exploration, development or acquisition activities, our reserves and production
will decline. We may not be able to find, develop or acquire additional reserves
at acceptable costs.
To the
extent that we succeed in discovering oil and/or natural gas, reserves may not
be capable of production levels we project or in sufficient quantities to be
commercially viable. On a long-term basis, our company’s viability depends on
our ability to find or acquire, develop and commercially produce additional oil
and gas reserves. Without the addition of reserves through exploration,
acquisition or development activities, our reserves and production will decline
over time as reserves are produced. Our future reserves will depend not only on
our ability to develop then-existing properties, but also on our ability to
identify and acquire additional suitable producing properties or prospects, to
find markets for the oil and natural gas we develop and to effectively
distribute our production into our markets.
Future
oil and gas exploration may involve unprofitable efforts, not only from dry
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of
drilling, completion and operating costs. In addition, drilling hazards or
environmental damage could greatly increase the cost of operations, and various
field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or
consents, shut-downs of connected wells resulting from extreme weather
conditions, problems in storage and distribution and adverse geological and
mechanical conditions. While we will endeavor to effectively manage these
conditions, we may not be able to do so optimally, and we will not be able to
eliminate them completely in any case. Therefore, these conditions could
diminish our revenue and cash flow levels and result in the impairment of our
oil and natural gas interests.
We are Required
to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain
These Licenses Could Cause Significant Delays and Expenses That Could Materially
Impact Our Business.
We are
subject to licensing and permitting requirements relating to drilling for oil
and natural gas. We may not be able to obtain, sustain or renew such licenses.
Regulations and policies relating to these licenses and permits may change or be
implemented in a way that we do not currently anticipate. These licenses and
permits are subject to numerous requirements, including compliance with the
environmental regulations of the local governments. As we are not the operator
of all the joint ventures we are currently involved in, we may rely on the
operator to obtain all necessary permits and licenses. If we fail to comply with
these requirements, we could be prevented from drilling for oil and natural gas,
and we could be subject to civil or criminal liability or fines. Revocation or
suspension of our environmental and operating permits could have a material
adverse effect on our business, financial condition and results of
operations.
34
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.
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.
35
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 2006 was $66 per barrel, in 2007 it was $72 per barrel, in 2008 it
was $100 per barrel, and in 2009 it was $62 per barrel. However, the average
price for the three months ended March 31, 2010 was $78.63, demonstrating the
inherent volatility in the market. We expect that prices will
fluctuate in the future. Price fluctuations will have a significant impact upon
our revenue, the return from our oil and gas reserves and on our financial
condition generally. Price fluctuations for oil and natural gas commodities may
also impact the investment market for companies engaged in the oil and gas
industry. Furthermore, prices which we receive for our oil sales,
while based on international oil prices, are established by contract with
purchasers with prescribed deductions for transportation and quality
differences. These differentials can change over time and have a detrimental
impact on realized prices. Future decreases in the prices of oil and natural gas
may have a material adverse effect on our financial condition, the future
results of our operations and quantities of reserves recoverable on an economic
basis.
In
addition, oil and natural gas prices in Argentina are effectively regulated and
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.
36
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.
If our
property rights are reduced, whether by governmental action or third party
challenges, our ability to conduct our exploration, development and production
may be impaired.
We Will Rely on
Technology to Conduct Our Business and Our Technology Could Become Ineffective
Or Obsolete.
We rely
on technology, including geographic and seismic analysis techniques and economic
models, to develop our reserve estimates and to guide our exploration and
development and production activities. We will be required to continually
enhance and update our technology to maintain its efficacy and to avoid
obsolescence. The costs of doing so may be substantial, and may be higher than
the costs that we anticipate for technology maintenance and development. If we
are unable to maintain the efficacy of our technology, our ability to manage our
business and to compete may be impaired. Further, even if we are able to
maintain technical effectiveness, our technology may not be the most efficient
means of reaching our objectives, in which case we may incur higher operating
costs than we would were our technology more efficient.
Risks Related to Our Common
Stock
The Market Price
of Our Common Stock May Be Highly Volatile and Subject to Wide
Fluctuations.
The
market price of our common stock may be highly volatile and could be subject to
wide fluctuations in response to a number of factors that are beyond our
control, including but not limited to:
·
|
dilution
caused by our issuance of additional shares of common stock and other
forms of equity securities, which we expect to make in connection with
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;
|
37
·
|
announcements
of new acquisitions, reserve discoveries or other business initiatives by
our competitors;
|
·
|
fluctuations
in revenue from our oil and natural gas
business;
|
·
|
changes
in the market and/or WTI price for oil and natural gas commodities and/or
in the capital markets generally;
|
·
|
changes
in the demand for oil and natural gas, including changes resulting from
the introduction or expansion of alternative fuels;
and
|
·
|
changes
in the social, political and/or legal climate in the regions in which we
will operate.
|
In
addition, the market price of our common stock could be subject to wide
fluctuations in response to various factors, which could include the following,
among others:
·
|
quarterly
variations in our revenues and operating
expenses;
|
·
|
changes
in the valuation of similarly situated companies, both in our industry and
in other industries;
|
·
|
changes
in analysts’ estimates affecting our company, our competitors and/or our
industry;
|
·
|
changes
in the accounting methods used in or otherwise affecting our
industry;
|
·
|
additions
and departures of key personnel;
|
·
|
announcements
of technological innovations or new products available to the oil and
natural gas industry;
|
·
|
announcements
by relevant governments pertaining to incentives for alternative energy
development programs;
|
·
|
fluctuations
in interest rates, exchange rates and the availability of capital in the
capital markets; and
|
·
|
significant
sales of our common stock, including sales by future investors in future
offerings we expect to make to raise additional
capital.
|
These and
other factors are largely beyond our control, and the impact of these risks,
singularly or in the aggregate, may result in material adverse changes to the
market price of our common stock and/or our results of operations and financial
condition.
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.
ITEM 2. UNREGISTERED SALES
OF EQUITY SECURITIES AND USE OF PROCEEDS
On twelve
separate dates beginning on January 1, 2010 and ending on March 31, 2010, we
sold an aggregate of 972,080 shares of our common stock for an aggregate
purchase price of $1,158,234. These shares were issued to thirteen 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 original purchasers of the
warrants, who had represented to us in the private placement of the warrants
that they were accredited investors as defined in Regulation D under the
Securities Act.
On two
separate dates between January 1, 2010 and March 31, 2010 we
issued 1,886,508 shares of our common stock to two holders of
exchangeable shares, which were issued by a subsidiary of Gran Tierra in a share
exchange on November 10, 2005. The shares were issued to this holder in reliance
on Regulation S promulgated by the SEC as the investor was not a resident of the
United States.
38
ITEM 6.
EXHIBITS
See Index
to Exhibits at the end of this Report, which is incorporated by reference here.
The Exhibits listed in the accompanying Index to Exhibits are filed as part of
this report.
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
GRAN
TIERRA ENERGY INC.
|
Date:
May 10, 2010
|
/s/
Dana Coffield
|
|
By:
Dana Coffield
|
||
Its:
Chief Executive Officer
|
Date:
May 10, 2010
|
/s/
Martin Eden
|
|
By:
Martin Eden
|
||
Its:
Chief Financial Officer
|
39
EXHIBIT
INDEX
Exhibit
|
No.
|
Description
|
Reference
|
||||||
2.1
|
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 (Reg. No.
001-34018), filed with the SEC on August 1, 2008.
|
||||||
2.2
|
Amendment
No. 2 to Arrangement Agreement, which supersedes Amendment No. 1 thereto
and 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 (Reg.
No. 001-34018), filed with the SEC on January 6, 2010.
|
||||||
3.2
|
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. 000-52594).
|
||||||
4.1
|
Reference
is made to Exhibits 3.1 to 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).
|
||||||
31.1
|
Rule
13a-14(a)/15d-14(a) Certification of Principal Executive
Officer
|
Filed
herewith.
|
||||
31.2
|
Rule
13a-14(a)/15d-14(a) Certification of Principal Financial
Officer
|
Filed
herewith.
|
||||
32.1
|
Section
1350 Certifications.
|
Filed
herewith.
|
||||
40