Attached files
file | filename |
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EX-32.1 - GRAN TIERRA ENERGY INC. | v164907_ex32-1.htm |
EX-31.2 - GRAN TIERRA ENERGY INC. | v164907_ex31-2.htm |
EX-31.1 - GRAN TIERRA ENERGY INC. | v164907_ex31-1.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 September 30, 2009
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
000-52594
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,
611 10th
Avenue SW
Calgary,
Alberta, Canada
|
T2R
0B2
|
|
(Address
of principal executive offices)
|
(Zip
code)
|
(403) 265-3221
(Registrant’s
telephone number,
including
area code)
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.
Large
Accelerated Filer x
|
Accelerated
Filer ¨
|
Non-Accelerated
Filer ¨
|
(do
not check if a smaller reporting company) Smaller Reporting
Company ¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). YES o NO x
On
November 3, 2009, the following numbers of shares of the registrant’s capital
stock were outstanding: 216,259,799 shares of the registrant’s Common Stock,
$0.001 par value; one share of Special A Voting Stock, $0.001 par
value, representing 10,411,905 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 16,324,391 shares of Gran Tierra Exchangeco Inc.,
which are exchangeable on a 1-for-1 basis into the registrant’s Common
Stock.
TABLE OF
CONTENTS
Page
|
||
PART
I - FINANCIAL INFORMATION
|
||
ITEM
1.
|
FINANCIAL
STATEMENTS
|
3
|
ITEM
2.
|
MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
20
|
ITEM
3.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
34
|
ITEM
4.
|
CONTROLS
AND PROCEDURES
|
35
|
ITEM
4T.
|
CONTROLS
AND PROCEDURES
|
35
|
PART
II - OTHER INFORMATION
|
||
ITEM
1.
|
LEGAL
PROCEEDINGS
|
35
|
ITEM
1A.
|
RISK
FACTORS
|
36
|
ITEM
2.
|
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
46
|
ITEM
3.
|
DEFAULTS
UPON SENIOR SECURITIES
|
46
|
ITEM
4.
|
SUBMISSION
OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
|
46
|
ITEM
5.
|
OTHER
INFORMATION
|
47
|
ITEM
6.
|
EXHIBITS
|
47
|
SIGNATURES
|
47
|
|
EXHIBIT
INDEX
|
47
|
2
PART I -
FINANCIAL INFORMATION
ITEM 1 - FINANCIAL
STATEMENTS
Gran
Tierra Energy Inc.
Condensed
Consolidated Statements of Operations and Retained Earnings (Accumulated
Deficit) (Unaudited)
(Thousands
of U.S. Dollars, Except Share and Per Share Amounts)
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
REVENUE
AND OTHER INCOME
|
||||||||||||||||
Oil
and natural gas sales
|
$ | 75,171 | $ | 40,082 | $ | 166,606 | $ | 93,873 | ||||||||
Interest
|
183 | 257 | 824 | 429 | ||||||||||||
75,354 | 40,339 | 167,430 | 94,302 | |||||||||||||
EXPENSES
|
||||||||||||||||
Operating
|
9,099 | 4,513 | 25,063 | 10,766 | ||||||||||||
Depletion,
depreciation and accretion
|
35,246 | 6,757 | 95,466 | 15,221 | ||||||||||||
General
and administrative
|
7,076 | 4,036 | 19,226 | 12,810 | ||||||||||||
Derivative
financial instruments (gain) loss (Note 10)
|
(77 | ) | (4,475 | ) | 207 | 2,987 | ||||||||||
Foreign
exchange (gain) loss
|
18,867 | (1,351 | ) | 32,353 | (1,734 | ) | ||||||||||
70,211 | 9,480 | 172,315 | 40,050 | |||||||||||||
INCOME
(LOSS) BEFORE INCOME TAXES
|
5,143 | 30,859 | (4,885 | ) | 54,252 | |||||||||||
Income
tax expense (Note 7)
|
(7,959 | ) | (7,872 | ) | (11,999 | ) | (18,063 | ) | ||||||||
NET
INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
|
(2,816 | ) | 22,987 | (16,884 | ) | 36,189 | ||||||||||
RETAINED
EARNINGS (ACCUMULATED DEFICIT), BEGINNING OF PERIOD
|
(7,084 | ) | (3,309 | ) | 6,984 | (16,511 | ) | |||||||||
RETAINED
EARNINGS (ACCUMULATED DEFICIT), END OF PERIOD
|
$ | (9,900 | ) | $ | 19,678 | $ | (9,900 | ) | $ | 19,678 | ||||||
NET
INCOME (LOSS) PER SHARE — BASIC
|
$ | (0.01 | ) | $ | 0.20 | $ | (0.07 | ) | $ | 0.34 | ||||||
NET
INCOME (LOSS) PER SHARE — DILUTED
|
$ | (0.01 | ) | $ | 0.18 | $ | (0.07 | ) | $ | 0.30 | ||||||
WEIGHTED
AVERAGE SHARES OUTSTANDING - BASIC (Note 5)
|
242,232,717 | 114,324,583 | 240,585,878 | 105,509,871 | ||||||||||||
WEIGHTED
AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)
|
242,232,717 | 128,303,724 | 240,585,878 | 119,733,940 |
(See
notes to the condensed consolidated financial statements)
3
Gran
Tierra Energy Inc.
Condensed
Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars)
September 30,
|
December 31,
|
|||||||
2009
|
2008
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
$ | 151,599 | $ | 176,754 | ||||
Restricted
cash
|
1,892 | - | ||||||
Accounts
receivable
|
77,657 | 7,905 | ||||||
Inventory
(Note 2)
|
3,375 | 999 | ||||||
Taxes
receivable
|
1,046 | 5,789 | ||||||
Prepaids
|
1,001 | 1,103 | ||||||
Derivative
financial instruments (Note 10)
|
- | 233 | ||||||
Deferred
tax assets (Note 7)
|
1,299 | 2,262 | ||||||
Total
Current Assets
|
237,869 | 195,045 | ||||||
Oil
and Gas Properties (using the full cost method of
accounting)
|
||||||||
Proved
|
362,256 | 380,855 | ||||||
Unproved
|
362,825 | 384,195 | ||||||
Total
Oil and Gas Properties
|
725,081 | 765,050 | ||||||
Other
capital assets
|
2,852 | 2,502 | ||||||
Total
Property, Plant and Equipment (Note 4)
|
727,933 | 767,552 | ||||||
Other
Long Term Assets
|
||||||||
Deferred
tax assets (Note 7)
|
3,940 | 10,131 | ||||||
Other
long term assets
|
1,067 | 1,315 | ||||||
Goodwill
|
98,210 | 98,582 | ||||||
Total
Other Long Term Assets
|
103,217 | 110,028 | ||||||
Total
Assets
|
$ | 1,069,019 | $ | 1,072,625 | ||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable (Note 8)
|
$ | 13,881 | $ | 21,134 | ||||
Accrued
liabilities (Note 8)
|
23,733 | 12,841 | ||||||
Derivative
financial instruments (Note 10)
|
61 | - | ||||||
Taxes
payable
|
11,124 | 28,163 | ||||||
Deferred
tax liability (Note 7)
|
- | 100 | ||||||
Asset
retirement obligation (Note 6)
|
290 | - | ||||||
Total
Current Liabilities
|
49,089 | 62,238 | ||||||
Deferred
tax liability (Note 7)
|
233,207 | 213,093 | ||||||
Deferred
remittance tax (Note 7)
|
1,281 | 1,117 | ||||||
Asset
retirement obligation (Note 6)
|
4,001 | 4,251 | ||||||
Total
Long Term Liabilities
|
238,489 | 218,461 | ||||||
Commitments
and Contingencies (Note 9)
|
||||||||
Shareholders’
Equity
|
||||||||
Common
shares (Note 5)
|
608 | 226 | ||||||
(214,865,802
and 190,248,384 common shares and 27,447,637 and 48,238,269 exchangeable
shares, par value $0.001 per share, issued and outstanding as at September
30, 2009 and December 31, 2008, respectively)
|
||||||||
Additional
paid in capital
|
762,190 | 753,236 | ||||||
Warrants
|
28,543 | 31,480 | ||||||
Retained
earnings (accumulated deficit)
|
(9,900 | ) | 6,984 | |||||
Total
Shareholders’ Equity
|
781,441 | 791,926 | ||||||
Total
Liabilities and Shareholders’ Equity
|
$ | 1,069,019 | $ | 1,072,625 |
(See
notes to the condensed consolidated financial statements)
4
Gran
Tierra Energy Inc.
Condensed
Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
Nine Months Ended September 30,
|
||||||||
2009
|
2008
|
|||||||
Operating
Activities
|
||||||||
Net
income (loss)
|
$ | (16,884 | ) | $ | 36,189 | |||
Adjustments
to reconcile net income (loss) to net cash (used in) provided by operating
activities:
|
||||||||
Depletion,
depreciation and accretion
|
95,466 | 15,221 | ||||||
Deferred
taxes
|
(5,650 | ) | (7,729 | ) | ||||
Stock
based compensation
|
3,483 | 1,265 | ||||||
Unrealized
loss on financial instruments
|
294 | 242 | ||||||
Unrealized
foreign exchange loss
|
32,982 | - | ||||||
Settlement
of asset retirement obligations (Note 6)
|
(52 | ) | - | |||||
Net
changes in non-cash working capital
|
||||||||
Accounts
receivable
|
(68,633 | ) | (26,584 | ) | ||||
Inventory
|
(286 | ) | 217 | |||||
Prepaids
|
102 | (48 | ) | |||||
Accounts
payable and accrued liabilities
|
6,501 | 6,967 | ||||||
Taxes
receivable and payable
|
(12,296 | ) | 18,705 | |||||
Net
cash provided by operating activities
|
35,027 | 44,445 | ||||||
Investing
Activities
|
||||||||
Restricted
cash
|
(1,892 | ) | - | |||||
Oil
and gas property and other capital asset expenditures
|
(65,595 | ) | (26,587 | ) | ||||
Proceeds
from disposition of oil and gas property (Note 4)
|
4,800 | - | ||||||
Long
term assets and liabilities
|
248 | (30 | ) | |||||
Net
cash used in investing activities
|
(62,439 | ) | (26,617 | ) | ||||
Financing
Activities
|
||||||||
Proceeds
from issuance of common stock
|
2,257 | 21,743 | ||||||
Net
cash provided by financing activities
|
2,257 | 21,743 | ||||||
Net
(decrease) increase in cash and cash equivalents
|
(25,155 | ) | 39,571 | |||||
Cash
and cash equivalents, beginning of period
|
176,754 | 18,189 | ||||||
Cash
and cash equivalents, end of period
|
$ | 151,599 | $ | 57,760 | ||||
Cash
|
$ | 66,980 | $ | 22,165 | ||||
Term
deposits
|
84,619 | 35,595 | ||||||
Cash
and cash equivalents, end of period
|
$ | 151,599 | $ | 57,760 | ||||
Supplemental
cash flow disclosures:
|
||||||||
Cash
paid for taxes
|
$ | 27,896 | $ | 9,701 | ||||
Non-cash
investing activities:
|
||||||||
Non-cash
working capital related to capital additions
|
$ | 8,233 | $ | 13,574 |
(See
notes to the condensed consolidated financial statements)
5
Gran
Tierra Energy Inc.
Condensed
Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands
of U.S. Dollars)
Nine Months Ended
|
Year Ended
|
|||||||
September 30, 2009
|
December 31, 2008
|
|||||||
Share
Capital
|
||||||||
Balance,
beginning of period
|
$ | 226 | $ | 95 | ||||
Issue
of common shares
|
382 | 131 | ||||||
Balance,
end of period
|
608 | 226 | ||||||
Additional
Paid in Capital
|
||||||||
Balance,
beginning of period
|
753,236 | 72,458 | ||||||
Issue
of common shares
|
1,313 | 663,405 | ||||||
Issue
of stock options in a business combination
|
- | 1,345 | ||||||
Exercise
of warrants
|
2,937 | 12,864 | ||||||
Exercise
of stock options
|
562 | 72 | ||||||
Stock
based compensation expense
|
4,142 | 3,092 | ||||||
Balance,
end of period
|
762,190 | 753,236 | ||||||
Warrants
|
||||||||
Balance,
beginning of period
|
31,480 | 20,750 | ||||||
Issue
of warrants
|
- | 23,594 | ||||||
Exercise
of warrants
|
(2,937 | ) | (12,864 | ) | ||||
Balance,
end of period
|
28,543 | 31,480 | ||||||
Retained
Earnings (Accumulated Deficit)
|
||||||||
Balance,
beginning of period
|
6,984 | (16,511 | ) | |||||
Net
income (loss)
|
(16,884 | ) | 23,495 | |||||
Balance,
end of period
|
(9,900 | ) | 6,984 | |||||
Total
Shareholders’ Equity
|
$ | 781,441 | $ | 791,926 |
(See
notes to the condensed consolidated financial statements)
6
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 September 30, 2009, the results of its operations
for the three and nine month periods ended September 30, 2009 and 2008, and its
cash flows for the nine month periods ended September 30, 2009 and
2008.
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, 2008 included in the Company’s 2008
Annual Report on Form 10-K, filed with the Securities and Exchange Commission
(“SEC”) on February 27, 2009. The Company’s significant accounting policies are
described in Note 2 of the consolidated financial statements which are included
in the Company’s 2008 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 evaluated all subsequent events through November 5,
2009, the date the unaudited interim consolidated financial statements were
issued.
Inventory
Crude oil
inventories at September 30, 2009 and December 31, 2008 are $2.9 million and
$0.8 million, respectively. Supplies at September 30, 2009 and December 31, 2008
are $0.5 million and $0.2 million, respectively.
New Accounting
Pronouncements
In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
Accounting Standard Codification (“ASC”) 820-10 (formerly Statement of Financial
Accounting Standards (“SFAS”) 157) “Fair Value Measurements”. ASC 820-10 defines
fair value, establishes a framework for measuring fair value under US GAAP and
expands disclosures about fair value measurements. This statement is effective
for fiscal years beginning after November 15, 2007. In February 2008, the
FASB issued ASC 820-10-15-1A (formerly FASB Staff Position (“FSP”) SFAS 157-2)
which delays the effective date of ASC 820-10 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least annually),
until fiscal years beginning after November 15, 2008, and interim periods
within those fiscal years. These nonfinancial items include assets and
liabilities such as reporting units measured at fair value in a goodwill
impairment test, asset retirement obligations and nonfinancial assets acquired
and liabilities assumed in a business combination. In October 2008, the FASB
also issued ASC 820-10-35-15A (formerly FSP SFAS 157-3 (superseded by ASC
820-10-65-1 (formerly FSP SFAS 157-4))), “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active,” which clarifies
the application of ASC 820-10 in an inactive market and illustrates how an
entity would determine fair value when the market for a financial asset is not
active. Effective January 1, 2008, the Company adopted ASC 820-10 for
financial assets and liabilities. The partial adoption of ASC 820-10 for
financial assets and liabilities did not have a material impact on the Company’s
consolidated financial position, results of operations or cash flows. See
Note 10 for information and related disclosures. Effective January 1, 2009,
the Company adopted the provisions for nonfinancial assets and nonfinancial
liabilities that are not required or permitted to be measured at fair value on a
recurring basis, which include those measured at fair value in goodwill
impairment testing, indefinite-lived intangible assets measured at fair value
for impairment assessment, nonfinancial long-lived assets measured at fair value
for impairment assessment, asset retirement obligations initially measured at
fair value, and those initially measured at fair value in a business
combination. The adoption of ASC 820-10 related to these items
on January 1, 2009 did not materially impact the Company’s consolidated
financial position, results of operations or cash flows.
7
In
December 2007, the FASB issued ASC 805-10 (formerly SFAS 141 (R)), “Business
Combinations”, and ASC 810-10-65 (formerly SFAS 160), “Non-controlling
Interests in Consolidated Financial Statements”. ASC 805-10 requires an
acquirer to measure the identifiable assets acquired, the liabilities assumed
and any non-controlling interest in the acquiree at their fair values on the
acquisition date, with goodwill being the excess value over the net identifiable
assets acquired. In April 2009, the FASB issued ASC 805-10-35-1 (formerly FSP
SFAS 141(R)-1), “Accounting for Assets Acquired and Liabilities Assumed in a
Business Combination That Arise from Contingencies,” which amends the guidance
in ASC 805-10 to require contingent assets acquired and liabilities assumed in a
business combination to be recognized at fair value on the acquisition date if
fair value can be reasonably estimated during the measurement
period. If fair value cannot be reasonably estimated during the
measurement period, the contingent asset or liability would be recognized in
accordance with ASC 450-10-05 (formerly SFAS No. 5), “Accounting for
Contingencies,” and ASC 450-20-55 (formerly FASB Interpretation (FIN) No. 14),
“Reasonable Estimation of the Amount of a Loss.” Further, ASC 805-10
eliminated the specific subsequent accounting guidance for contingent assets and
liabilities from ASC 805-10, without significantly revising the guidance in SFAS
No. 141. However, contingent consideration arrangements of an
acquiree assumed by the acquirer in a business combination would still be
initially and subsequently measured at fair value in accordance with ASC
805-10. ASC 805-10 was effective for all business acquisitions occurring on
or after the beginning of the first annual reporting period beginning on or
after December 15, 2008. ASC 810-10-65 (formerly SFAS 160) clarifies
that a non-controlling interest in a subsidiary should be reported as equity in
the consolidated financial statements. The calculation of earnings per share
will continue to be based on income amounts attributable to the parent. ASC
805-10 and ASC 810-10-65 were effective for financial statements issued for
fiscal years beginning after December 15, 2008. Early adoption is
prohibited and the provisions are applied prospectively. The adoption of these
statements and ASC 805-10 as of January 1, 2009 did not have a material effect
on the Company’s consolidated financial statements but these changes may affect
potential future business combinations.
In March
2008, the FASB issued ASC 815-10-15 (formerly SFAS 161), “Disclosures about
Derivative Instruments and Hedging Activities”. ASC 815-10-15 requires companies
with derivative instruments to disclose information that should enable financial
statement users to understand how and why a company uses derivative instruments,
how derivative instruments and related hedged items are accounted for under ASC
815-10 (formerly SFAS 133), “Accounting for Derivative Instruments and
Hedging Activities” and how derivative instruments and related hedged items
affect a company's financial position, financial performance and cash flows. ASC
815-10-15 is effective for financial statements issued for fiscal
years and interim periods beginning after November 15, 2008. The adoption
of ASC 815-10-15 on January 1, 2009 did not have a material effect on the
Company’s consolidated financial statements.
In April
2008, the FASB issued ASC 350-30 (formerly FSP 142-3), “Determination of the
Useful Life of Intangible Assets”. ASC 350-30 amends the factors that
should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under ASC 350-10
(formerly SFAS 142), “Goodwill and Other Intangible Assets”. ASC 350-30 is
effective for financial statements issued for fiscal years beginning after
December 15, 2008. Early adoption is prohibited. The adoption of ASC 350-30
on January 1, 2009 did not have a material impact on the Company’s consolidated
financial statements.
In June
2008, the FASB ratified the consensus reached on ASC 815-40-15 (formerly
Emerging Issues Task Force “EITF” 07-05), “Determining Whether an
Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” ASC
815-40-15 clarifies the determination of whether an instrument (or an embedded
feature) is indexed to an entity’s own stock, which would qualify as a scope
exception under ASC 815-10. ASC 815-40-15 is effective for financial statements
issued for fiscal years beginning after December 15, 2008. Early adoption
for an existing instrument is not permitted. The adoption of ASC 815-40-15 on
January 1, 2009 did not have a material effect on the Company’s consolidated
financial statements.
In
December 2008, the SEC released Final Rule, “Modernization of Oil
and Gas Reporting” to revise the existing Regulation S-K and Regulation S-X
reporting requirements to align with current industry practices and
technological advances. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes. In addition, the new disclosure requirements require a
company to (a) disclose its internal control over reserves estimation and report
the independence and qualification of its reserves preparer or auditor, (b) file
reports when a third party is relied upon to prepare reserves estimates or
conducts a reserve audit and (c) report oil and gas reserves using an average
price based upon the prior 12-month period rather than period-end prices. The
provisions of this final ruling are effective for disclosures in Gran Tierra’s
Annual Report on Form 10-K for the year ending December 31,
2009. Early adoption is not permitted. Gran Tierra is currently
assessing the impact that the adoption will have on the Company’s disclosures,
operating results, financial position and cash flows.
In April
2009, the FASB issued ASC 825-10-65-1 (formerly FSP SFAS 107-1), “Interim
Disclosures about Fair Value of Financial Instruments”, which amends ASC
825-10 (formerly SFAS 107), “Disclosures about Fair Value of Financial
Instruments”, and ASC 825-10 (formerly APB Opinion No. 28),
“Interim Financial Reporting”. ASC 825-10-65-1 requires disclosures about
fair value of financial instruments in financial statements for interim
reporting periods and in annual financial statements of publicly-traded
companies. ASC 825-10-65-1 also requires entities to disclose the method(s) and
significant assumptions used to estimate the fair value of financial
instruments in financial statements on an interim and annual basis and to
highlight any changes from prior periods. The effective date for ASC
825-10-65-1 is interim and annual periods ending after June 15, 2009. The
adoption of ASC 825-10-65-1 on April 1, 2009 did not have a material effect on
the Company’s consolidated financial statements.
In April
2009, the FASB issued ASC 320-10-65-1 (formerly FSP SFAS 115-2 and FAS 124-2),
“Recognition and Presentation of Other-Than-Temporary Impairments”.
ASC 320-10-65-1 amends the other-than-temporary impairment guidance for
debt securities to make the guidance more operational and to improve the
presentation and disclosure of other-than-temporary impairments on debt and
equity securities. ASC 320-10-65-1 is effective for interim and annual
periods ending after June 15, 2009. The adoption of ASC 320-10-65-1 on
April 1, 2009 did not have a material effect on the Company’s consolidated
financial statements.
8
In April
2009, the FASB issued ASC 820-10-65-4 (formerly FSP SFAS 157-4), “Determining
Fair Value When the Volume and Level of Activity for the Asset or Liability
Have Significantly Decreased and Identifying Transactions That Are Not
Orderly". ASC 820-10-65-4 provides additional guidance for estimating
fair value when the market activity for an asset or liability has declined
significantly. ASC 820-10-65-4 is effective for interim and annual periods
ending after June 15, 2009. The adoption of ASC 820-10-65-4 on April 1, 2009 did
not have a material effect on the Company’s consolidated financial
statements.
In May
2009, the FASB issued ASC 855-10 (formerly SFAS 165), “Subsequent Events”.
ASC 855-10 establishes the accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are issued or are
available to be issued. It requires the disclosure of the date through which an
entity has evaluated subsequent events and the basis for that date, that is,
whether that date represents the date the financial statements were issued or
were available to be issued. ASC 855-10 is effective for interim or
annual financial periods ending after June 15, 2009. The adoption of ASC 855-10
effective for the second quarter of 2009 did not have a material impact on the
Company’s consolidated financial statements.
In June
2009, the FASB issued ASC 860-10 (formerly SFAS 166), “Accounting for Transfers
of Financial Assets, an Amendment of FASB Statement No. 140”. ASC 860-10
amends ASC 860-10 (formerly SFAS 140), “Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities,” by:
eliminating the concept of a qualifying special-purpose entity (“QSPE”);
clarifying and amending the derecognition criteria for a transfer to be
accounted for as a sale; amending and clarifying the unit of account eligible
for sale accounting; and requiring that a transferor initially measure at fair
value and recognize all assets obtained (for example beneficial interests) and
liabilities incurred as a result of a transfer of an entire financial asset or
group of financial assets accounted for as a sale. Additionally, on and after
the effective date, existing QSPEs (as defined under previous accounting
standards) must be evaluated for consolidation by reporting entities in
accordance with the applicable consolidation guidance. ASC 860-10 requires
enhanced disclosures about, among other things, a transferor’s continuing
involvement with transfers of financial assets accounted for as sales, the risks
inherent in the transferred financial assets that have been retained, and the
nature and financial effect of restrictions on the transferor’s assets that
continue to be reported in the statement of financial position. ASC 860-10 will
be effective as of the beginning of interim and annual reporting periods that
begin after November 15, 2009. Gran Tierra is currently assessing the
impact that the adoption will have on the Company’s disclosures, operating
results, financial position and cash flows.
In June
2009, the FASB issued ASC 810-10 (formerly SFAS 167), “Amendments to FASB
Interpretation No. 46(R)”. ASC 810-10 amends ASC 810-10 (formerly FIN
46(R)), “Consolidation of Variable Interest Entities,” and changes the
consolidation guidance applicable to a variable interest entity (“VIE”). It also
amends the guidance governing the determination of whether an enterprise is the
primary beneficiary of a VIE, and is, therefore, required to consolidate an
entity, by requiring a qualitative analysis rather than a quantitative analysis.
The qualitative analysis will include, among other things, consideration of who
has the power to direct the activities of the entity that most significantly
impact the entity’s economic performance and who has the obligation to absorb
losses or the right to receive benefits of the VIE that could potentially be
significant to the VIE. This standard also requires continuous reassessments of
whether an enterprise is the primary beneficiary of a VIE. Previously, ASC
810-10 required reconsideration of whether an enterprise was the primary
beneficiary of a VIE only when specific events had occurred. QSPEs, which were
previously exempt from the application of this standard, will be subject to the
provisions of this standard when it becomes effective. ASC 810-10 also requires
enhanced disclosures about an enterprise’s involvement with a VIE. ASC 810-10
will be effective as of the beginning of interim and annual reporting periods
that begin after November 15, 2009. Gran Tierra is currently
assessing the impact that the adoption will have on the Company’s disclosures,
operating results, financial position and cash flows.
In
June 2009, the FASB issued ASC 105-10 (formerly SFAS 168), “The FASB
Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles”. ASC 105-10 is now the source of authoritative U.S. GAAP
recognized by the FASB to be applied by nongovernment entities. It also modifies
the GAAP hierarchy to include only two levels of GAAP; authoritative and
non-authoritative. ASC 105-10 is effective for financial statements issued for
interim and annual periods ending after September 15, 2009. The adoption of
ASC 105-10, effective for the third quarter of 2009, did not have a significant
impact on the Company’s consolidated financial statements.
In August
2009, the FASB issued Accounting Standards Update (“ASU”) No. 2009-05,
"Measuring Liabilities at Fair Value," which amends ASC 820, "Fair Value
Measurements and Disclosures." ASU 2009-05 provides clarification and
guidance regarding how to value a liability when a quoted price in an active
market is not available for that liability. The Company will adopt
the provisions of this update for fair value measurements of liabilities
effective October 1, 2009, and adoption is not expected to have a significant
impact on the Company’s consolidated financial statements.
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 on these land holdings is not significant at this
time and are included as part of the Corporate segment. The accounting policies
of the reportable operating segments are the same as those described in the
summary of significant accounting policies. The Company evaluates performance
based on profit or loss from oil and natural gas operations before price risk
management and income taxes.
9
Effective
November 14, 2008, the Company completed its 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 with its head office located in Calgary, Alberta, Canada. The results
of Colombia and Corporate segments include the operations of Solana subsequent
to the Company’s acquisition of Solana on November 14, 2008.
The
following tables present information on the Company’s reportable geographic
segments:
Three Months Ended September 30, 2009
|
||||||||||||||||
(Thousands of U.S. Dollars except per unit of
production amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 71,385 | $ | 3,786 | $ | - | $ | 75,171 | ||||||||
Interest
income
|
31 | 34 | 118 | 183 | ||||||||||||
Depreciation,
depletion & accretion
|
33,630 | 1,538 | 78 | 35,246 | ||||||||||||
Depreciation,
depletion & accretion - per unit of production
|
30.37 | 18.38 | - | 29.59 | ||||||||||||
Segment
income (loss) before income taxes
|
7,955 | 390 | (3,202 | ) | 5,143 | |||||||||||
Segment
capital expenditures (1)
|
$ | 17,024 | $ | 1,890 | $ | 210 | $ | 19,124 | ||||||||
Three Months Ended September 30,
2008
|
||||||||||||||||
(Thousands
of U.S. Dollars except per unit of
production
amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 37,733 | $ | 2,349 | $ | - | $ | 40,082 | ||||||||
Interest
income
|
138 | 8 | 111 | 257 | ||||||||||||
Depreciation,
depletion & accretion
|
6,129 | 593 | 35 | 6,757 | ||||||||||||
Depreciation,
depletion & accretion - per unit of production
|
18.44 | 11.09 | - | 17.51 | ||||||||||||
Segment
income (loss) before income taxes
|
29,972 | (942 | ) | 1,829 | 30,859 | |||||||||||
Segment
capital expenditures
|
$ | 5,109 | $ | 6,389 | $ | 3,052 | $ | 14,550 | ||||||||
Nine Months Ended September 30,
2009
|
||||||||||||||||
(Thousands
of U.S. Dollars except per unit of
production
amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 156,257 | $ | 10,349 | $ | - | $ | 166,606 | ||||||||
Interest
income
|
352 | 84 | 388 | 824 | ||||||||||||
Depreciation,
depletion & accretion
|
90,565 | 4,671 | 230 | 95,466 | ||||||||||||
Depreciation,
depletion & accretion - per unit of production
|
29.99 | 18.21 | - | 29.14 | ||||||||||||
Segment
income (loss) before income taxes
|
5,370 | (577 | ) | (9,678 | ) | (4,885 | ) | |||||||||
Segment
capital expenditures (1)
|
$ | 58,431 | $ | 3,162 | $ | 1,799 | $ | 63,392 | ||||||||
Nine Months Ended September 30,
2008
|
||||||||||||||||
(Thousands
of U.S. Dollars except per unit of
production
amounts)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Revenues
|
$ | 87,891 | $ | 5,982 | $ | - | $ | 93,873 | ||||||||
Interest
income
|
279 | 18 | 132 | 429 | ||||||||||||
Depreciation,
depletion & accretion
|
13,409 | 1,716 | 96 | 15,221 | ||||||||||||
Depreciation,
depletion & accretion - per unit of production
|
16.63 | 11.63 | - | 15.96 | ||||||||||||
Segment
income (loss) before income taxes
|
66,814 | (1,581 | ) | (10,981 | ) | 54,252 | ||||||||||
Segment
capital expenditures
|
$ | 18,259 | $ | 8,918 | $ | 5,144 | $ | 32,321 |
10
As at September 30, 2009
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant & equipment
|
$ | 695,275 | $ | 26,627 | $ | 6,031 | $ | 727,933 | ||||||||
Goodwill
|
98,210 | - | - | 98,210 | ||||||||||||
Other
assets
|
92,466 | 11,750 | 138,660 | 242,876 | ||||||||||||
Total
Assets
|
$ | 885,951 | $ | 38,377 | $ | 144,691 | $ | 1,069,019 | ||||||||
As at December 31, 2008
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant & equipment
|
$ | 735,208 | $ | 27,882 | $ | 4,462 | $ | 767,552 | ||||||||
Goodwill
|
98,582 | - | - | 98,582 | ||||||||||||
Other
assets
|
44,554 | 8,868 | 153,069 | 206,491 | ||||||||||||
Total
Assets
|
$ | 878,344 | $ | 36,750 | $ | 157,531 | $ | 1,072,625 |
(1) Net
of net proceeds from the disposition of the Guachiria Blocks (see Note
4).
The
Company’s revenues are derived principally from uncollateralized sales to
customers in the oil and natural gas industry. The concentration of credit risk
in a single industry affects the Company’s overall exposure to credit risk
because customers may be similarly affected by changes in economic and other
conditions. In 2009, the Company has one significant customer for its Colombian
crude oil, Ecopetrol S.A., a Colombian government agency. In Argentina, the
Company has one significant customer, Refineria del Norte S.A.
4. Property, Plant and
Equipment
As at September 30, 2009
|
As at December 31, 2008
|
|||||||||||||||||||||||
(Thousands of U.S. Dollars)
|
Cost
|
Accumulated
DD&A
|
Net book
value
|
Cost
|
Accumulated
DD&A
|
Net book
value
|
||||||||||||||||||
Oil
and natural gas properties
|
||||||||||||||||||||||||
Proved
|
$ | 495,530 | $ | (133,274 | ) | $ | 362,256 | $ | 419,539 | $ | (38,684 | ) | $ | 380,855 | ||||||||||
Unproved
|
362,825 | - | 362,825 | 384,195 | - | 384,195 | ||||||||||||||||||
858,355 | (133,274 | ) | 725,081 | 803,734 | (38,684 | ) | 765,050 | |||||||||||||||||
Furniture
and fixtures and leasehold improvements
|
3,773 | (2,168 | ) | 1,605 | 1,979 | (848 | ) | 1,131 | ||||||||||||||||
Computer
equipment
|
2,862 | (1,871 | ) | 991 | 1,791 | (526 | ) | 1,265 | ||||||||||||||||
Automobiles
|
361 | (105 | ) | 256 | 163 | (57 | ) | 106 | ||||||||||||||||
Total
Property, Plant and Equipment
|
$ | 865,351 | $ | (137,418 | ) | $ | 727,933 | $ | 807,667 | $ | (40,115 | ) | $ | 767,552 |
During
the nine months ended September 30, 2009, the Company capitalized $2.4 million
(year ended December 31, 2008 - $1.9 million) of general and administrative
expenses related to the Colombian full cost center, including $0.5 million (year
ended December 31, 2008 - $0.4 million) of stock based compensation expense, and
$0.4 million (year ended December 31, 2008 - $0.8 million) of general and
administrative expenses in the Argentina full cost center, including $0.1
million (year ended December 31, 2008 - $0.1 million) of stock based
compensation.
The
unproved oil and natural gas properties at September 30, 2009 consist of
exploration lands held in Colombia, Argentina and Peru. As at September 30,
2009, the Company had $353.9 million (December 31, 2008 - $375.9 million)
in unproved assets in Colombia, $3.7 million (December 31, 2008 - $4.7
million) of unproved assets in Argentina and $5.2 million (December 31, 2008 -
$3.6 million) of unproved assets in Peru. These properties are being held for
their exploration value and are not being depleted pending determination of the
existence of proved reserves. Gran Tierra will continue to assess and allocate
the unproved properties over the next several years as proved reserves are
established and as exploration dictates whether or not future areas will be
developed.
11
In April
2009, Gran Tierra closed the sale of the Company’s interests in the Guachiria
Norte, Guachiria, and Guachiria Sur Blocks in Colombia. Principal terms included
consideration of $7.0 million comprising an initial cash payment of $4.0 million
at closing, followed by 15 monthly installments of $200,000 each which began on
June 1, 2009 and extending through August 3, 2010. The Company recorded net
proceeds of $6.3 million. Gran Tierra retained a 10% overriding royalty interest
on the Guachiria Sur Block, which, in the event of a discovery, is designed to
reimburse 200% of our costs for previously acquired seismic data.
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 (collectively, “common stock”), and two shares are designated
as special voting stock, par value $0.001 per share. On June 16, 2009, the
shareholders of Gran Tierra approved an amendment to the Articles of
Incorporation to increase the authorized number of shares of common stock from
300,000,000 to 570,000,000 shares. As at September 30, 2009, outstanding share
capital consists of 214,865,802 common voting shares of the Company, 16,877,002
exchangeable shares of Gran Tierra Exchange Co., and 10,570,635 exchangeable
shares of Goldstrike Exchange Co. 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
September 30, 2009, the Company has 5,629,314 warrants outstanding to purchase
2,814,657 common shares for $1.25 per share, 12,147,682 warrants outstanding to
purchase 6,073,841 common shares for $1.05 per share and 7,145,938 warrants
assumed upon the acquisition of Solana to purchase 7,145,938 common shares for
CDN$2.10 per share. For the nine months ended September 30, 2009, 3,224,216
common shares were issued upon the exercise of 8,919,706 warrants (nine months
ended September 30, 2008, 20,209,385 common shares were issued upon the exercise
of 40,598,048 warrants).
Stock
Options
As at
September 30, 2009, the Company has a 2007 Equity Incentive Plan, formed through
the approval by shareholders of the amendment and restatement of the 2005 Equity
Incentive Plan, under which the Company’s board of directors is authorized to
issue options or other rights to acquire shares of the Company’s common stock.
On November 14, 2008, the shareholders of Gran Tierra approved an amendment to
the Company’s 2007 Equity Incentive Plan, which increased the number of shares
of common stock available for issuance thereunder from 9,000,000 shares to
18,000,000 shares.
The
Company grants options to purchase common shares to certain directors, officers,
employees and consultants. Each option permits the holder to purchase one common
share at the stated exercise price. The options vest over three years and have a
term of ten years, or the grantee’s end of service to the Company, whichever
occurs first. At the time of grant, the exercise price equals the market price.
For the nine months ended September 30, 2009, 602,570 common shares were issued
upon the exercise of 602,570 stock options (nine months ended September 30,
2008 – 209,164). The following options are outstanding as of September 30,
2009:
|
Number of
|
Weighted Average
|
||||||
Outstanding
|
Exercise Price
|
|||||||
Options
|
$/Option
|
|||||||
Outstanding,
December 31, 2008
|
11,406,870 | $ | 2.13 | |||||
Granted
in 2009
|
945,000 | 3.06 | ||||||
Exercised
in 2009
|
(602,570 | ) | (1.56 | ) | ||||
Forfeited
in 2009
|
(352,226 | ) | (3.03 | ) | ||||
Outstanding,
September 30, 2009
|
11,397,074 | $ | 2.21 |
The
weighted average grant date fair value for options granted in 2009 was $1.85.
The intrinsic value of options exercised for the nine months ended September 30,
2009 was $922,682 (nine months ended September 30, 2008 -
$854,925).
12
The table
below summarizes stock options outstanding at September 30, 2009:
Number of
|
Weighted Average
|
Weighted
|
||||||||||
Outstanding
|
Exercise Price
|
Average
|
||||||||||
Range of Exercise Prices ($/option)
|
Options
|
$/Option
|
Expiry Years
|
|||||||||
0.50
to 1.00
|
935,001 | $ | 0.80 | 6.1 | ||||||||
1.01
to 1.30
|
1,640,000 | 1.26 | 7.2 | |||||||||
1.31
to 2.00
|
447,419 | 1.76 | 7.2 | |||||||||
2.01
to 3.00
|
7,674,654 | 2.41 | 9.0 | |||||||||
3.01
to 10.00
|
700,000 | 4.36 | 9.4 | |||||||||
Total
|
11,397,074 | $ | 2.21 | 8.4 |
The
aggregate intrinsic value of options outstanding at September 30, 2009 is $22.6
million based on the Company’s closing stock price of $4.16 for that date. At
September 30, 2009, there was $5.3 million of unrecognized compensation cost
related to unvested stock options which is expected to be recognized over the
next three years.
For the
nine months ended September 30, 2009, the stock based compensation expense
was $4.1 million (nine months ended September 30, 2008 - $1.7 million) of which
$3.3 million (nine months ended September 30, 2008 - $1.1 million) was recorded
in general and administrative expense and $0.2 million was recorded in operating
expense in the consolidated statement of operations (nine months ended September
30, 2008 – $0.2 million). For the nine months ended September 30, 2009,
$0.6 million of stock based compensation was capitalized as part of exploration
and development costs (nine months ended September 30, 2008 – $0.4
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 September 30,
|
Nine Months Ended September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Dividend
yield (per share)
|
$ | nil | $ | nil | $ | nil | $ | nil | ||||||||
Volatility
|
97 | % | 89 | % | 97 | % |
75%
to 92%
|
|||||||||
Risk-free
interest rate
|
0.5 | % | 2.1 | % | 0.5 | % | 2.1 | % | ||||||||
Expected
term
|
3
years
|
3
years
|
3
years
|
3
years
|
||||||||||||
Estimated
forfeiture percentage (per year)
|
10 | % | 10 | % | 10 | % | 10 | % |
Weighted average shares
outstanding
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Weighted
average number of common and exchangeable shares
outstanding
|
242,232,717 | 114,324,583 | 240,585,878 | 105,509,871 | ||||||||||||
Shares
issuable pursuant to warrants
|
- | 10,710,501 | - | 10,776,592 | ||||||||||||
Shares
issuable pursuant to stock options
|
- | 3,640,571 | - | 3,682,831 | ||||||||||||
Shares
to be purchased from proceeds of stock options
|
- | (371,931 | ) | - | (235,354 | ) | ||||||||||
Weighted
average number of diluted common and exchangeable shares
outstanding
|
242,232,717 | 128,303,724 | 240,585,878 | 119,733,940 |
Income (loss) per
share
For the
three and nine month periods ended September 30, 2009, options to purchase
11,397,074 common shares were excluded from the diluted loss per share
calculation as the instruments were anti-dilutive. For the three and nine month
periods ended September 30, 2009, 24,922,934 warrants to purchase 16,034,436
common shares were excluded from the diluted loss per share calculation as the
instruments were anti-dilutive. For the three and nine months ended September
30, 2008, options to purchase 100,000 common shares were excluded from the
diluted income per share calculation as the instruments were
anti-dilutive.
13
6. Asset Retirement
Obligation
As
at September 30, 2009 the Company’s asset retirement obligation was
comprised of a Colombian obligation in the amount of $3.3 million (December 31,
2008 - $3.5 million) and an Argentine obligation in the amount of $1.0 million
(December 31, 2008 - $0.8 million). Changes in the carrying amounts of the asset
retirement obligations associated with the Company’s oil and natural gas
properties were as follows:
(Thousands of U.S. Dollars)
|
Nine Months Ended September 30, 2009
|
Year Ended December 31, 2008
|
||||||
Balance,
beginning of period
|
$ | 4,251 | $ | 799 | ||||
Liability
assumed in a business combination
|
- | 3,148 | ||||||
Settlements
|
(52 | ) | (334 | ) | ||||
Disposal
|
(734 | ) | - | |||||
Liability
incurred
|
532 | 615 | ||||||
Foreign
exchange
|
41 | (29 | ) | |||||
Accretion
|
253 | 52 | ||||||
Balance,
end of period
|
$ | 4,291 | $ | 4,251 | ||||
Asset
retirement obligation - current
|
$ | 290 | $ | - | ||||
Asset
retirement obligation - long term
|
4,001 | 4,251 | ||||||
Balance,
end of period
|
$ | 4,291 | $ | 4,251 |
7. Income
Taxes
The
income tax expenses (recoveries) reported differ from the amount computed
by applying the Canadian statutory rate to income before income taxes for the
following reasons:
Nine Months Ended September 30,
|
||||||||
(Thousands of U.S. Dollars)
|
2009
|
2008
|
||||||
Income
(loss) before income taxes
|
$ | (4,885 | ) | $ | 54,252 | |||
29.00 | % | 29.50 | % | |||||
Income
tax expense (benefit) expected
|
(1,417 | ) | 16,004 | |||||
Impact
of current period tax losses not recognized
|
8,264 | (1,022 | ) | |||||
Foreign
currency translation adjustments
|
6,641 | - | ||||||
Depreciation
on inflationary adjustments
|
(155 | ) | - | |||||
Utilization
of foreign tax credits
|
- | (17,800 | ) | |||||
Impact
of foreign taxes
|
1,413 | 1,629 | ||||||
Enhanced
tax depreciation incentive
|
(831 | ) | (1,852 | ) | ||||
Stock
based compensation
|
141 | 249 | ||||||
Non-deductible
items
|
1,448 | 122 | ||||||
Previously
unrecognized tax assets
|
- | 3,420 | ||||||
Partnership
income (loss) pick-up in the United States and Canada
|
(3,505 | ) | 19,710 | |||||
Recognition
of foreign tax credits
|
(2,222 | ) | ||||||
Other
|
- | (175 | ) | |||||
Total
income tax expense
|
$ | 11,999 | $ | 18,063 |
14
As at
|
||||||||
(Thousands of U.S. Dollars)
|
September 30, 2009
|
December 31, 2008
|
||||||
Deferred
Tax Assets
|
||||||||
Tax
benefit of loss carryforwards
|
$ | 17,244 | $ | 16,905 | ||||
Book
value in excess of tax basis
|
800 | 1,228 | ||||||
Foreign
tax credits and other accruals
|
10,719 | 9,595 | ||||||
Capital
losses
|
1,492 | 1,419 | ||||||
Deferred
tax assets before valuation allowance
|
30,255 | 29,147 | ||||||
Valuation
allowance
|
(25,016 | ) | (16,754 | ) | ||||
$ | 5,239 | $ | 12,393 | |||||
Deferred
tax assets - current
|
$ | 1,299 | $ | 2,262 | ||||
Deferred
tax assets - long-term
|
3,940 | 10,131 | ||||||
5,239 | 12,393 | |||||||
Deferred
Tax Liabilities
|
||||||||
Current
- book value in excess of tax basis
|
- | (100 | ) | |||||
Long-term
- book value in excess of tax basis
|
(233,207 | ) | (213,093 | ) | ||||
(233,207 | ) | (213,193 | ) | |||||
Net
Deferred Tax Liabilities
|
$ | (227,968 | ) | $ | (200,800 | ) |
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 September 30,
2009 was $1.3 million (December 31, 2008 - $1.1 million).
The
Company has accrued no amounts as of September 30, 2009, for the potential
payment of interest and penalties. For the three and nine month periods ended
September 30, 2009, the Company has not recognized any amounts in respect of
potential interest and penalties associated with uncertain tax positions. The
Company and its subsidiaries file income tax returns in the U.S. federal
jurisdiction, various state jurisdictions and other foreign jurisdictions, as
applicable. The Company is subject to income tax examinations for the calendar
tax years ended 2005 through 2008 in various, but not all,
jurisdictions.
As at
September 30, 2009, the Company has deferred tax assets relating to net
operating loss carryforwards of $22.5 million (December 31, 2008 - $17.0
million) and capital losses of $1.5 million (December 31, 2008 – $1.4 million)
before valuation allowances. Of these losses, $18.4 million (December 31, 2008 -
$17.0 million) are losses generated by the foreign subsidiaries of the Company.
Of the total losses, nil will expire at the end of 2009 (December 31, 2008 -
nil), $1.5 million (December 31, 2008 - $1.4 million) will begin to expire by
2011 and $22.5 million of net operating losses (December 31, 2008 - $17.0
million) will begin to expire thereafter.
8. Accounts Payable and Accrued
Liabilities
The
balances in accrued liabilities and accounts payable are comprised of the
following:
As at September 30, 2009
|
||||||||||||||||
(Thousands of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant and equipment
|
$ | 15,276 | $ | 852 | $ | 166 | $ | 16,294 | ||||||||
Payroll
|
568 | 265 | 732 | 1,565 | ||||||||||||
Audit,
legal, consultants
|
- | 103 | 1,123 | 1,226 | ||||||||||||
General
and administrative
|
741 | 9 | 454 | 1,204 | ||||||||||||
Operating
|
15,965 | 1,360 | - | 17,325 | ||||||||||||
Total
|
$ | 32,550 | $ | 2,589 | $ | 2,475 | $ | 37,614 |
15
As at December 31, 2008
|
||||||||||||||||
(Thousands
of U.S. Dollars)
|
Colombia
|
Argentina
|
Corporate
|
Total
|
||||||||||||
Property,
plant and equipment
|
$ | 11,654 | $ | 1,254 | $ | 4 | $ | 12,912 | ||||||||
Payroll
|
978 | 435 | 921 | 2,334 | ||||||||||||
Audit,
legal, consultants
|
- | 126 | 1,351 | 1,477 | ||||||||||||
General
and administrative
|
1,193 | 52 | 898 | 2,143 | ||||||||||||
Operating
|
13,309 | 1,800 | - | 15,109 | ||||||||||||
Total
|
$ | 27,134 | $ | 3,667 | $ | 3,174 | $ | 33,975 |
9. Commitments and
Contingencies
Leases
Gran
Tierra holds four categories of operating leases: office, compressor, vehicle
and housing. Future lease payments at September 30, 2009 are as
follows:
As at September 30, 2009
|
||||||||||||||||||||
Payments Due in Period
|
||||||||||||||||||||
Contractual Obligations
|
Total
|
Less than 1
Year
|
1 to 3
years
|
3 to 5
years
|
More than 5
years
|
|||||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||
Operating
leases
|
$ | 5,191 | $ | 2,161 | $ | 2,706 | $ | 324 | $ | - | ||||||||||
Drilling,
completion, facility construction and oil transportation
services
|
20,426 | 18,257 | 2,169 | - | - | |||||||||||||||
Total
|
$ | 25,617 | $ | 20,418 | $ | 4,875 | $ | 324 | $ | - |
Guarantees
Corporate
indemnities have been provided by the Company to directors and officers for
various items including, but not limited to, all costs to settle suits or
actions due to their association with the Company and its subsidiaries and/or
affiliates, subject to certain restrictions. The Company has purchased
directors’ and officers’ liability insurance to mitigate the cost of any
potential future suits or actions. The maximum amount of any potential future
payment cannot be reasonably estimated.
The
Company may provide indemnifications in the normal course of business that are
often standard contractual terms to counterparties in certain transactions such
as purchase and sale agreements. The terms of these indemnifications will vary
based upon the contract, the nature of which prevents the Company from making a
reasonable estimate of the maximum potential amounts that may be required to be
paid. Management believes the resolution of these matters would not have a
material adverse impact on the Company’s liquidity, consolidated financial
position or results of operations.
Contingencies
Ecopetrol and
Gran Tierra Energy Colombia Ltd. “Gran Tierra Colombia”, the
contracting parties of the Guayuyaco Association Contract, are engaged in a
dispute regarding the interpretation of the procedure for allocation of oil
produced and sold during the long term test of the Guayuyaco-1 and Guayuyaco-2
wells. There is a material difference in the interpretation of the procedure
established in Clause 3.5 of Attachment-B of the Guayuyaco Association Contract.
Ecopetrol interprets the contract to provide that the extended test production
up to a value equal to 30% of the direct exploration costs of the wells is for
Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the
Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is
merely the recovery of 30% of the direct exploration costs of the wells and not
exclusively for benefit of Ecopetrol. There has been no agreement between the
parties, and Ecopetrol has filed a lawsuit in the Contravention
Administrative Court in the District of Cauca regarding this matter. Gran
Tierra Colombia filed a response on April 29, 2008 in which it refuted all of
Ecopetrol’s claims and requested a change of venue to the courts in
Bogotá. At this time no amount has been accrued in the financial
statements as the Company does not consider it probable that a loss will be
incurred. Ecopetrol is claiming damages of approximately $5.4 million. To the
Company’s knowledge, there are no other legal proceedings against Gran
Tierra.
16
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
September 30, 2009, the fair values of financial instruments approximate their
book amounts due to the short term maturity of these instruments. Most of the
Company’s accounts receivable relate to oil and natural gas sales and are
exposed to typical industry credit risks. The Company manages this credit risk
by entering into sales contracts with only credit worthy entities and reviewing
its exposure to individual entities on a regular basis. The book value of the
accounts receivable reflects management’s assessment of the associated credit
risks.
Additionally,
foreign exchange gains/losses result from the fluctuation of the U.S. dollar to
the Colombian peso due to Gran Tierra’s deferred tax liability, a monetary
liability, which is mainly denominated in the local currency of the
Colombian foreign operations. As a result, a foreign exchange gain/loss
must be calculated on conversion to the US dollar functional currency. A
strengthening in the Colombian peso against the U.S. dollar results in foreign
exchange losses, estimated at $70,000 for each one peso decrease in the exchange
rate of the Colombian peso to one U.S. dollar.
The
Company’s revenues are derived principally from uncollateralized sales to
customers in the oil and natural gas industry. The concentration of credit risk
in a single industry affects the Company’s overall exposure to credit risk
because customers may be similarly affected by changes in economic and other
conditions. In 2009, the Company has one significant customer for its Colombian
crude oil, Ecopetrol. In Argentina, the Company has one significant customer,
Refineria del Norte S.A.
The
Company recognizes the fair value of its derivative instruments as assets or
liabilities on the balance sheet. None of the Company's derivative
instruments currently qualify as fair value hedges or cash flow hedges, and
accordingly, changes in fair value of the derivative instruments are
recognized as income or expense in the consolidated statement of operations
and retained earnings (accumulated deficit) with a corresponding adjustment to
the fair value of derivative instruments recorded on the balance sheet. Under
the terms of the Credit Facility with Standard Bank (Note 11), the Company was
required to enter into a derivative instrument for the purpose of obtaining
protection against fluctuations in the price of oil in respect of at least 50%
of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate
net share of Colombian production after royalties for the three year term of the
Facility. In accordance with the terms of the Facility, the Company entered into
a costless collar derivative instrument for crude oil based on West Texas
Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for
a three year period ending February 2010, for 400 barrels per day from March
2007 to December 2007, 300 barrels per day from January 2008 to
December 2008, and 200 barrels per day from January 2009 to
February 2010.
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
(Thousands of U.S. Dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Realized
financial derivative (gain) loss
|
$ | - | $ | 1,052 | $ | (87 | ) | $ | 2,745 | |||||||
Unrealized
financial derivative (gain) loss
|
(77 | ) | (5,527 | ) | 294 | 242 | ||||||||||
Derivative
financial instruments (gain) loss
|
$ | (77 | ) | $ | (4,475 | ) | $ | 207 | $ | 2,987 |
As at September 30,
|
As at December 31,
|
|||||||
Assets (Liabilities)
|
2009
|
2008
|
||||||
Derivative
financial instruments
|
$ | (61 | ) | $ | 233 |
Certain
of Gran Tierra’s assets and liabilities are reported at fair value in the
accompanying balance sheets. The following tables provide fair value measurement
information for such assets and liabilities as at September 30, 2009 and
December 31, 2008.
The
carrying values of cash and cash equivalents, restricted cash, accounts
receivable and accounts payable (including accrued liabilities) included in the
accompanying consolidated balance sheets approximated fair value at September
30, 2009 and December 31, 2008. These assets and liabilities are not presented
in the following tables.
17
As at September 30, 2009
|
||||||||||||||||||||
Fair Value Measurements Using:
|
||||||||||||||||||||
Quoted
|
Significant
|
|||||||||||||||||||
Prices in
|
Other
|
Significant
|
||||||||||||||||||
Active
|
Observable
|
Unobservable
|
||||||||||||||||||
Carrying
|
Total
Fair
|
Markets
|
Inputs
|
Inputs
|
||||||||||||||||
Amount
|
Value
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||||||
Financial
Liabilities
|
||||||||||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||
Crude
oil collar
|
$ | (61 | ) | $ | (61 | ) | $ | - | $ | (61 | ) | $ | - | |||||||
As at December 31, 2008
|
||||||||||||||||||||
Fair Value Measurements
Using:
|
||||||||||||||||||||
Quoted
|
Significant
|
|||||||||||||||||||
Prices
in
|
Other
|
Significant
|
||||||||||||||||||
Active
|
Observable
|
Unobservable
|
||||||||||||||||||
Carrying
|
Total
Fair
|
Markets
|
Inputs
|
Inputs
|
||||||||||||||||
Amount
|
Value
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||||||
Financial
Assets
|
||||||||||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||
Crude
oil collar
|
$ | 233 | $ | 233 | $ | - | $ | 233 | $ | - |
ASC
820-10 establishes a fair value hierarchy that prioritizes the inputs to
valuation techniques used to measure fair value. As presented in the table
above, this hierarchy consists of three broad levels. Level 1 inputs on the
hierarchy consist of unadjusted quoted prices in active markets for identical
assets and liabilities and have the highest priority. Level 2 and 3 inputs have
lower priorities. The Company uses appropriate valuation techniques based on the
available inputs to measure the fair values of assets and liabilities. When
available, Gran Tierra measures fair value using Level 1 inputs because
they generally provide the most reliable evidence of fair value.
The
Company uses a Level 2 method to measure the fair value of its crude oil
collars. The fair values of the crude oil are estimated using internal
discounted cash flow calculations based upon forward commodity price curves,
quotes obtained from brokers for contracts with similar terms or quotes obtained
from counterparties to the agreements. The Company does not have any other
assets or liabilities whose fair value is measured using Level 1 or 3
methods.
The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the table above.
Level 1
Fair Value Measurements
The
Company does not have any assets or liabilities whose fair value is measured
using this method.
Level 2 Fair Value
Measurements
Crude oil collars — The
fair values of the crude oil collars are estimated using internal discounted
cash flow calculations based upon forward commodity price curves, quotes
obtained from brokers for contracts with similar terms or quotes obtained from
counterparties to the agreements.
Level 3
Fair Value Measurements
The
Company does not have any financial assets or financial liabilities whose fair
value is measured using this method.
11.
Credit Facilities
Effective
February 28, 2007, the Company entered into a credit facility with Standard
Bank Plc. The facility has a three year term which may be extended by
agreement between the parties. The borrowing base was the present value of the
Company’s petroleum reserves of a subsidiary, Gran Tierra Colombia, up to
maximum of $50 million. The Company recently completed negotiations with
Standard Bank Plc to increase the maximum amount of the credit facility to $200
million. Final documents were signed on August 24,
2009. The initial borrowing base is $7 million and the borrowing
base can be re-determined semi-annually based on reserve evaluation reports. As
a result of Standard Bank Plc’s review of Gran Tierra’s 2008 Independent Reserve
Audit, the Company has the capacity to increase the borrowing base to $120
million under the revised facility; however, this has not been pursued further
as the additional borrowing base is not required at this time. The facility
includes a letter of credit sub-limit of $5 million. Amounts drawn down under
the facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1%
per annum is charged on the un-drawn amount of the borrowing base. The facility
is secured primarily by the assets of Gran Tierra Colombia and Solana Petroleum
Exploration (Colombia) Ltd. Under the terms of the facility, the Company is
required to maintain and is in compliance with specified financial and operating
covenants. Gran Tierra was required to enter into a derivative instrument for
the purpose of obtaining protection against fluctuations in the price of oil in
respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation
Report projected aggregate net share of Colombian production after royalties for
the three-year term of the Facility. As at September 30, 2009, no amounts have
been drawn-down under this facility.
18
Following
the acquisition of Solana, effective November 14, 2008, Gran Tierra obtained
access to an additional credit facility with BNP Paribas. The
facility had a maturity date of December 20, 2010. The borrowing base
was $26 million, based on the current value of petroleum reserves of the
subsidiary, Solana Petroleum Exploration (Colombia) Ltd., up to a maximum of
$100 million. This facility was cancelled effective August 4, 2009 as a result
of the successful negotiations with Standard Bank to increase the maximum amount
available under that facility.
12.
Related Party Transaction
On
February 1, 2009, the Company entered into a sublease for office space
with a company, of which two of Gran Tierra’s directors are shareholders and
directors. The term of the sublease runs from February 1, 2009 to
August 31, 2011 and the sublease payment is $7,600 per month plus approximately
$3,900 for operating and other expenses. The terms of the sublease were
consistent with market conditions in the Calgary, Alberta, Canada real
estate market.
19
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 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 result, 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 27, 2009.
Overview
We are an
independent international energy company incorporated in the United States and
engaged in oil and natural gas exploration, development and production. We are
headquartered in Calgary, Alberta, Canada and operate in South America in
Colombia, Argentina and Peru, 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”). Upon completion of the transaction, Solana became an indirect
wholly-owned subsidiary of Gran Tierra. Solana is an international resource
company engaged in the acquisition, exploration, development and production of
oil and natural gas. Solana is incorporated in Alberta, Canada with
its head office in Calgary, Alberta. At the date of acquisition, Solana held
various working interests in nine blocks in Colombia and was the operator of six
of those blocks, four of which contained producing assets. As a result of the
acquisition and the subsequent sale of the Guachiria Norte, Guachiria Sur and
Guachiria Blocks acquired from Solana, Gran Tierra has increased its working
interest in two of the producing blocks and has retained a working interest in
four of the seven other purchased blocks.
During
the third quarter of 2009, we opened a business development office in Rio de
Janeiro, Brazil.
The oil
and gas industry has been adversely impacted by the downturn in the global
economy and the decline in average crude oil prices during the first three
quarters of 2009 compared to the same period in 2008. Although our revenue has
been negatively affected by these lower oil prices, our current liquidity
position has mitigated the impact of these adverse market conditions. We believe
that our current operations and capital expenditure program can be maintained
from cash flow from existing operations, cash on hand and our credit facilities,
barring unforeseen events. We also have the ability to defer or cancel portions
of our capital expenditure program should our operating cash flows decline as a
result of reductions in crude oil prices.
20
Financial
and Operational Highlights (1)
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||||||||||||||||||||||
2009
|
2008
|
% Change
|
2009
|
2008
|
% Change
|
|||||||||||||||||||
Production
- Barrels of Oil Equivalent per Day
|
12,945 | 4,194 | 209 | 12,000 | 3,482 | 245 | ||||||||||||||||||
Per
Barrel of Oil Equivalent Prices Realized
|
$ | 63.12 | $ | 103.88 | (39 | ) | $ | 50.86 | $ | 98.40 | (48 | ) | ||||||||||||
Revenue
and Other Income ($000's)
|
$ | 75,354 | $ | 40,339 | 87 | $ | 167,430 | $ | 94,302 | 78 | ||||||||||||||
Net
Income (Loss) ($000's)
|
$ | (2,816 | ) | $ | 22,987 | (112 | ) | $ | (16,884 | ) | $ | 36,189 | (147 | ) | ||||||||||
Net
Income (Loss) Per Share - Basic
|
$ | (0.01 | ) | $ | 0.20 | (105 | ) | $ | (0.07 | ) | $ | 0.34 | (121 | ) | ||||||||||
Net
Income (Loss) Per Share - Diluted
|
$ | (0.01 | ) | $ | 0.18 | (106 | ) | $ | (0.07 | ) | $ | 0.30 | (123 | ) | ||||||||||
Capital
Expenditures ($000's)
|
$ | 19,124 | $ | 14,550 | 31 | $ | 63,392 | $ | 32,321 | 96 |
As at September 30,
|
As at December 31,
|
|||||||||||
2009
|
2008
|
% Change
|
||||||||||
Cash
& Cash Equivalents ($000's)
|
$ | 151,599 | $ | 176,754 | (14 | ) | ||||||
Working
Capital (including cash & cash equivalents) ($000's)
|
$ | 188,780 | $ | 132,807 | 42 | |||||||
Property,
Plant & Equipment ($000's)
|
$ | 727,933 | $ | 767,552 | (5 | ) |
(1) The
Financial and Operating Highlights include the operations of Solana subsequent
to our acquisition of Solana on November 14, 2008.
Financial Highlights for
Three Months Ended September 30, 2009
·
|
In
the third quarter of 2009, production of crude oil (net after royalty and
inventory adjustments) averaged 12,945 barrels of oil per day
(“BOPD”), an increase of 209% over the same period in 2008, due mainly to
production from four new development wells in the Costayaco field in the
Chaza Block in Colombia where Gran Tierra has a 100% working interest
subsequent to the acquisition of
Solana.
|
·
|
Revenue
and other income increased by 87% over the same period in 2008 due
to increased production partially offset by lower oil
prices.
|
·
|
A
foreign exchange loss of $18.9 million, of which $20.3 million is an
unrealized non-cash foreign exchange loss, was recorded in the third
quarter of 2009 primarily due to the translation of a deferred tax
liability recorded on the purchase of Solana. The deferred tax liability
is denominated in Colombian pesos and the devaluation of 11% in the US
dollar against the Colombian Peso in the current quarter resulted in the
foreign exchange loss.
|
·
|
Oil
and gas property expenditures for the third quarter of 2009 include
further development drilling in the Costayaco field including the
successful drilling of the Costayaco – 9 well in addition to facility
construction at Costayaco, and seismic programs in the Rio Magdelena and
San Pablo Blocks.
|
·
|
Our
cash position of $151.6 million (excluding restricted cash) at September
30, 2009 decreased from $176.8 million at December 31, 2008 as a result of
year-to-date capital expenditures, partially offset by cash provided
by operating activities.
|
·
|
Working
capital (including cash & cash equivalents) was $188.8 million at
September 30, 2009, which is a $56.0 million increase from December 31,
2008, due mainly to increased receivables as at September 30, 2009
compared to December 31, 2008.
|
·
|
Property,
plant & equipment as at September 30, 2009 was $727.9 million, a
decrease from December 31, 2008, primarily as a result of increased
depletion, depreciation and accretion (“DD&A”), partially offset by
capital additions.
|
21
·
|
Standard
Bank Plc increased the maximum amount of our credit facility to $200
million, effective August 24, 2009. No amounts have been drawn down under
this facility.
|
Financial Highlights for
Nine Months Ended September 30,
2009
·
|
During
the first three quarters of 2009, production of crude oil and natural gas
(net after royalty and inventory adjustments) averaged 12,000 barrels of
oil equivalent per day, an increase of 245% over the same period in 2008,
due mainly to production from four new development wells in the Costayaco
field in the Chaza Block in Colombia where Gran Tierra has a 100% working
interest subsequent to the acquisition of
Solana.
|
·
|
Revenue
and other income increased by 78% over the same period in 2008 due to the
increased production, partially offset by lower oil
prices.
|
·
|
A
foreign exchange loss of $32.4 million, of which $33.0 million is an
unrealized non-cash foreign exchange loss, was recorded in the first three
quarters of 2009 primarily due to the translation of a deferred tax
liability recorded on the purchase of Solana. The deferred tax liability
is denominated in Colombian pesos and the devaluation of 14% in the US
dollar against the Colombian Peso in the first three quarters of 2009
resulted in the foreign exchange
loss.
|
·
|
Oil
and gas property expenditures for the nine months ended September 30, 2009
include further development drilling in the Costayaco field, including
Costayaco – 6, Costayaco – 7, Costayaco – 8, and Costayaco – 9, facility
construction in Costayaco, the drilling of the Puinaves – 2 exploration
well in the Guachiria Norte Block and acquisition of 2D or 3D seismic in
the Guachiria, Garibay, Rio Magdelena, Chaza, and San Pablo Blocks, all in
Colombia.
|
Operational Highlights for
the Three and Nine Months Ended September 30, 2009
·
|
Costayaco
Field Oil Production
Milestones
|
At the
end of August 2009, we reached our daily production plateau target of 19,000
BOPD gross for the Costayaco field. In addition, production from the Costayaco
field in Colombia reached five million cumulative barrels of gross oil
production on September 10, 2009 triggering additional government
royalties.
·
|
Successful
Production Testing of Costayaco
- 8 and Costayaco -
9
|
In June
2009, we completed logging operations and initiated production testing of
Costayaco – 8. Testing of Costayaco – 8 was completed in early July and the well
came on production later in the month. In August 2009, after further testing, it
was determined that Costayaco – 7 will be completed as a water injector well to
dispose of produced water from the Costayaco field, and to provide pressure
support for the Villeta T reservoir. In September 2009, we completed logging
operations and production testing of Costayaco – 9. Testing of Costayaco – 9 was
completed in early September and the well was tied in and put on production
later in the month.
·
|
New
Exploration and Exploitation Contracts in
Colombia
|
In June
2009, we signed three Exploration and Exploitation contracts with the National
Hydrocarbon Agency totaling 235,264 acres in which we have a 100% working
interest. The Piedemonte Norte Block lies southwest of the Chaza Block where the
Costayaco field is located. The Piedemonte Sur Block is located immediately west
of the Orito Field, the largest oil field in the Putumayo
Basin. Further south, the Rumiyaco Block is located in the central
Putumayo Basin.
·
|
Property
Divestment
|
In April
2009, Gran Tierra closed the sale of its interests in the Guachiria Norte,
Guachiria, and Guachiria Sur Blocks in Colombia for net proceeds of $6.3
million.
·
|
Environmental
Impact Assessments submitted to Peruvian
Government
|
The
seismic and stratigraphic drilling environmental impact assessments were
submitted to the Peruvian Government in April 2009, for Block 128, and in
June 2009, for Block 122. Consultations with communities in the region have
concluded.
22
Consolidated Results of
Operations
Three Months Ended September
30,
|
Nine Months Ended September
30,
|
|||||||||||||||||||||||
Consolidated
Results of
Operations
(1)
|
2009
|
2008
|
% Change
|
2009
|
2008
|
% Change
|
||||||||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 75,171 | $ | 40,082 | 88 | $ | 166,606 | $ | 93,873 | 77 | ||||||||||||||
Interest
|
183 | 257 | (29 | ) | 824 | 429 | 92 | |||||||||||||||||
75,354 | 40,339 | 87 | 167,430 | 94,302 | 78 | |||||||||||||||||||
Operating
expenses
|
9,099 | 4,513 | 102 | 25,063 | 10,766 | 133 | ||||||||||||||||||
Depletion,
depreciation and accretion
|
35,246 | 6,757 | 422 | 95,466 | 15,221 | 527 | ||||||||||||||||||
General
and administrative expenses
|
7,076 | 4,036 | 75 | 19,226 | 12,810 | 50 | ||||||||||||||||||
Derivative
financial instruments (gain) loss
|
(77 | ) | (4,475 | ) | (98 | ) | 207 | 2,987 | (93 | ) | ||||||||||||||
Foreign
exchange (gain) loss
|
18,867 | (1,351 | ) | (1,497 | ) | 32,353 | (1,734 | ) | (1,966 | ) | ||||||||||||||
70,211 | 9,480 | 641 | 172,315 | 40,050 | 330 | |||||||||||||||||||
Income
(loss) before income taxes
|
5,143 | 30,859 | (83 | ) | (4,885 | ) | 54,252 | (109 | ) | |||||||||||||||
Income
tax expense
|
(7,959 | ) | (7,872 | ) | 1 | (11,999 | ) | (18,063 | ) | (34 | ) | |||||||||||||
Net
income (loss)
|
$ | (2,816 | ) | $ | 22,987 | (112 | ) | $ | (16,884 | ) | $ | 36,189 | (147 | ) | ||||||||||
Production,
Net of Royalties
|
||||||||||||||||||||||||
Oil
and NGL's ("bbl") (2)
|
1,190,954 | 385,886 | 209 | 3,273,597 | 953,957 | 243 | ||||||||||||||||||
Natural
gas ("mcf")
|
- | - | - | 49,028 | - | - | ||||||||||||||||||
Total
production ("boe") (2) (3)
|
1,190,954 | 385,886 | 209 | 3,276,048 | 953,957 | 243 | ||||||||||||||||||
Average
Prices
|
||||||||||||||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 63.12 | $ | 103.88 | (39 | ) | $ | 50.84 | $ | 98.40 | (48 | ) | ||||||||||||
Natural
gas ("per mcf")
|
$ | - | $ | - | - | $ | 3.91 | $ | - | - | ||||||||||||||
Consolidated
Results of
Operations
("per boe")
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 63.12 | $ | 103.88 | (39 | ) | $ | 50.86 | $ | 98.40 | (48 | ) | ||||||||||||
Interest
|
0.15 | 0.66 | (77 | ) | 0.25 | 0.45 | (44 | ) | ||||||||||||||||
63.27 | 104.54 | (39 | ) | 51.11 | 98.85 | (48 | ) | |||||||||||||||||
Operating
expenses
|
7.64 | 11.70 | (35 | ) | 7.65 | 11.29 | (32 | ) | ||||||||||||||||
Depletion,
depreciation and accretion
|
29.59 | 17.51 | 69 | 29.14 | 15.96 | 83 | ||||||||||||||||||
General
and administrative expenses
|
5.94 | 10.46 | (43 | ) | 5.87 | 13.43 | (56 | ) | ||||||||||||||||
Derivative
financial instruments loss
|
(0.06 | ) | (11.60 | ) | (99 | ) | 0.06 | 3.13 | (98 | ) | ||||||||||||||
Foreign
exchange (gain) loss
|
15.84 | (3.50 | ) | (553 | ) | 9.88 | (1.82 | ) | (643 | ) | ||||||||||||||
58.95 | 24.57 | 140 | 52.60 | 41.99 | 25 | |||||||||||||||||||
Income
(loss) before income taxes
|
4.32 | 79.97 | (95 | ) | (1.49 | ) | 56.86 | (103 | ) | |||||||||||||||
Income
tax expenses
|
(6.68 | ) | (20.40 | ) | (67 | ) | (3.66 | ) | (18.93 | ) | (81 | ) | ||||||||||||
Net
income (loss)
|
$ | (2.36 | ) | $ | 59.57 | (104 | ) | $ | (5.15 | ) | $ | 37.93 | (114 | ) |
(1)
Consolidated results of operations include the operations of Solana subsequent
to our acquisition of Solana on November 14, 2008.
(2) Gas
volumes are converted to barrels of oil equivalent (“boe”) at the rate of 20
thousand cubic feet ("mcf") of gas per barrel of oil based upon the approximate
relative values of natural gas and oil. Natural gas liquid (“NGL”) volumes are
converted to boe on a one-to-one basis with oil.
(3)
Production represents production volumes adjusted for inventory
changes.
23
Consolidated Results of Operations for the Three and Nine Months Ended September 30, 2009 compared to the Results
for the Three and Nine Months Ended September 30, 2008
As a
result of the Solana acquisition, we increased our working interest to 100% in
the Costayaco field and 70% in the Juanambu field, in Colombia, which resulted
in increased production, revenue, operating costs, and DD&A in
2009.
A net
loss of $2.8 million, or a loss of $0.01 per share basic and diluted, was
recorded for the three months ended September 30, 2009 compared to net income of
$23.0 million, or $0.20 per share basic and $0.18 per share diluted, for the
same period in 2008. A foreign exchange loss of $18.9 million, of which $20.3
million is an unrealized non-cash foreign exchange loss, an increase of $28.5
million in DD&A to $35.2 million and higher operating and general and
administrative expenses, more than offset the higher oil revenues for the
current quarter. Net income for the third quarter of 2008 included a loss of
$4.5 million from derivative financial instruments. A net loss of $16.9 million,
or a loss of $0.07 per share basic and diluted, was recorded for the nine months
ended September 30, 2009 compared to net income of $36.2 million, or $0.34 per
share basic and $0.30 per share diluted, for the same period in 2008. Increased
oil and natural gas sales of $72.7 million resulting from higher production were
more than offset by lower crude oil prices, an increase of $80.2 million in
DD&A mostly related to the Solana assets, increases in operating expenses
and general and administrative expenses, and a foreign exchange loss of $32.4
million, of which $33.0 million is an unrealized non-cash foreign exchange loss,
resulting primarily from translation of deferred taxes recorded on the purchase
of Solana.
Revenue and
interest increased 87% to $75.4 million for the three months ended
September 30, 2009 compared to $40.3 million in the same period in
2008. This was due to an increase of 209% in crude oil production
partially offset by a decrease in crude oil prices. For the nine
months ended September 30, 2009 revenue and interest increased 78% to $167.4
million compared to the same period in 2008 for the same reasons cited
above.
Crude oil and NGL
production, net after royalties, for the three months ended September 30,
2009 increased to 1,190,954 barrels compared to 385,886 barrels for the same
period in 2008, and for the nine months ended September 30, 2009
production increased to 3,273,597 barrels compared to 953,957 barrels for
the same period in 2008, due mainly to increased production from our Colombia
operations. Average realized crude oil prices for the current quarter decreased
to $63.12 per barrel ($50.84 per barrel for the first nine months of 2009) from
$103.88 per barrel for the three months ended September 30, 2008 ($98.40 per
barrel for the first nine months of 2008), reflecting lower WTI oil
prices.
Operating
expenses for the third quarter of 2009 amounted to $9.1 million, a 102%
increase from the same period in 2008. Operating expenses for the nine months
ended September 30, 2009 increased to $25.1 million from $10.8 million in the
same period last year. The increase in operating expenses is due to
expanded operations and increased production levels in Colombia. However, for
the three months ended September 30, 2009, operating expenses on a boe basis
were $7.64 per boe, a 35% decline from the same period in 2008 due to the impact
of the high production wells and lower operating expenses at Costayaco. A
similar decline for the same reason was also recorded for the nine months ended
September 30, 2009 with operating expenses of $7.65 per boe compared to $11.29
per boe, a 32% decline, from the same period in 2008.
DD&A expense
for the current quarter increased to $35.2 million compared to $6.8 million for
the same quarter in 2008 and increased to $95.5 million for the first three
quarters of 2009 compared to $15.2 million for the same period in 2008.
Increased production levels as well as amortization expense of $26.9
million for the quarter ($72.4 million for the nine months of 2009) related to
the fair value of property, plant and equipment recorded on the acquisition of
Solana accounted for the increases. On a boe basis, DD&A in the third
quarter was $29.59 compared to $17.51 for the same period in 2008. This 69%
increase was primarily due to the significant additions to the proved depletable
cost base resulting from the Solana acquisition partially offset by higher
proved reserves in Colombia. DD&A for the nine months ended September 30,
2009 was $29.14 per boe as compared to $15.96 per boe for the same period in
2008 for the same reasons.
General and
administrative (“G&A”) expenses
of $7.1 million and $19.2 million for the three and nine months ended September
30, 2009, were 75% and 50% higher, respectively, than the same periods in 2008
due to increased employee related costs reflecting the expanded operations in
Colombia and 2008 stock option grants. However, due to higher production in
2009, G&A expenses per boe decreased 43% to $5.94 per boe for the current
quarter, compared to $10.46 per boe for the third quarter of 2008 and declined
by 56% to $5.87 per boe for the first nine months ended September 30, 2009
compared to $13.43 per boe for the same period in 2008.
Derivative
financial instruments gain for the three months ended September 30, 2009
was $0.1 million, while a loss of $0.2 million was recorded for the nine months
ended September 30, 2009, both from the costless collar financial derivative
contract for crude oil prices entered into pursuant to the terms and conditions
of Gran Tierra’s credit facility. A derivative financial instruments gain of
$4.5 million was recorded for the three months ended September 30, 2008 while a
loss of $3.0 million was recorded for the nine months ended September 30,
2008 related to the same derivative financial
instruments.
24
The foreign exchange
loss of $18.9 million, of which $20.3 million is an unrealized non-cash
foreign exchange loss, for the third quarter of 2009 and $32.4
million for the first nine months of 2009 of which $33.0 million is
unrealized non-cash foreign exchange loss primarily resulting from the
translation of a deferred tax liability recorded on the purchase of Solana. This
deferred tax liability, a monetary liability, is denominated in the local
currency of Colombia and as a result, foreign exchange gains and losses have
been calculated on conversion to the U.S. dollar functional
currency.
Income tax
expense for the three months ended September 30, 2009 amounted to $8.0
million compared to income tax expense of $7.9 million recorded in the same
period in 2008. An income tax expense of $12.0 million was recorded for the nine
months ended September 30, 2009 compared to an income tax expense of $18.1
million recorded for the same period in 2008. For the three and nine months
ended September 30, 2009, income tax expense related to operations increased by
1% and decreased by 34% respectively, primarily due to fluctuations in income
before taxes. The variance from the 29% Canadian statutory rate for both the
three and nine months ended September 30, 2009 is primarily attributable to
foreign currency translation fluctuations that are not taxable in the related
foreign jurisdictions, valuation allowances taken on losses incurred in the U.S.
and Canada, and the residual income tax incurred in jurisdictions with a higher
income tax rate than Canada. The variance from the 29.5% Canadian statutory
rate for the three months ended September 30, 2008 is primarily attributable to
the recognition of previously unrecognized foreign tax credits, which was
partially offset by an increase due to the majority of taxable income being
incurred in Colombia, which has a statutory tax rate of 33%.The variance from
the 29.5% Canadian statutory rate for the nine months ended September 30, 2008
is primarily attributable to the majority of taxable income being incurred
in jurisdictions with a local statutory rate which is higher than that of
Canada.
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 and nine months ended
September 30, 2009, Colombia generated 94.8% and 93.5%, respectively, of our
revenue and other income and reflects the operations of Solana subsequent to the
acquisition of Solana on November 14, 2008.
Segmented
Results – Colombia
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||||||||||||||||||||||
Segmented Results of
Operations – Colombia (1)
|
2009
|
2008
|
% Change
|
2009
|
2008
|
% Change
|
||||||||||||||||||
(Thousands
of U.S. Dollars)
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 71,385 | $ | 37,733 | 89 | $ | 156,257 | $ | 87,891 | 78 | ||||||||||||||
Interest
|
31 | 138 | (78 | ) | 352 | 279 | 26 | |||||||||||||||||
71,416 | 37,871 | 89 | 156,609 | 88,170 | 78 | |||||||||||||||||||
Operating
expenses
|
7,242 | 2,453 | 195 | 20,292 | 6,325 | 221 | ||||||||||||||||||
Depletion,
depreciation and accretion
|
33,630 | 6,129 | 449 | 90,565 | 13,409 | 575 | ||||||||||||||||||
General
and administrative expenses
|
2,777 | 692 | 301 | 7,396 | 3,212 | 130 | ||||||||||||||||||
Foreign
exchange (gain) loss
|
19,812 | (1,375 | ) | (1,541 | ) | 32,986 | (1,590 | ) | (2,175 | ) | ||||||||||||||
63,461 | 7,899 | 703 | 151,239 | 21,356 | 608 | |||||||||||||||||||
Segment
income before income taxes
|
$ | 7,955 | $ | 29,972 | (73 | ) | $ | 5,370 | $ | 66,814 | (92 | ) | ||||||||||||
Production, Net of
Royalties
|
||||||||||||||||||||||||
Oil
and NGL's ("bbl") (2)
|
1,107,265 | 332,382 | 233 | 3,017,078 | 806,382 | 274 | ||||||||||||||||||
Natural
gas ("mcf") (2)
|
- | - | - | 49,028 | - | - | ||||||||||||||||||
Total
production ("boe") (2) (3)
|
1,107,265 | 332,382 | 233 | 3,019,529 | 806,382 | 274 | ||||||||||||||||||
Average Prices
|
||||||||||||||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 64.47 | $ | 113.52 | (43 | ) | $ | 51.73 | $ | 108.99 | (53 | ) | ||||||||||||
Natural
gas ("per mcf")
|
$ | - | $ | - | - | $ | 3.91 | $ | - | - | ||||||||||||||
Segmented Results of
Operations ("per boe")
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 64.47 | $ | 113.52 | (43 | ) | $ | 51.75 | $ | 108.99 | (53 | ) | ||||||||||||
Interest
|
0.03 | 0.42 | (93 | ) | 0.12 | 0.35 | (66 | ) | ||||||||||||||||
64.50 | 113.94 | (43 | ) | 51.87 | 109.34 | (53 | ) | |||||||||||||||||
Operating
expenses
|
6.54 | 7.38 | (11 | ) | 6.72 | 7.84 | (14 | ) | ||||||||||||||||
Depletion,
depreciation and accretion
|
30.37 | 18.44 | 65 | 29.99 | 16.63 | 80 | ||||||||||||||||||
General
and administrative expenses
|
2.51 | 2.08 | 21 | 2.45 | 3.98 | (38 | ) | |||||||||||||||||
Foreign
exchange (gain) loss
|
17.89 | (4.14 | ) | (532 | ) | 10.92 | (1.97 | ) | (654 | ) | ||||||||||||||
57.31 | 23.76 | 141 | 50.08 | 26.48 | 89 | |||||||||||||||||||
Segment
income (loss) before income taxes
|
$ | 7.19 | $ | 90.18 | (92 | ) | $ | 1.79 | $ | 82.86 | (98 | ) |
25
(1)
|
Segmented
results of operations for Colombia include the operations of Solana
subsequent to our acquisition of Solana on November 14,
2008.
|
(2)
|
Gas
volumes are converted to barrels of oil equivalent (“boe”) at the rate of
20 thousand cubic feet ("mcf") of gas per barrel of oil based upon the
approximate relative values of natural gas and oil. NGL volumes are
converted to boe on a one to one basis with
oil.
|
(3)
|
Production
represents production volumes adjusted for inventory
changes.
|
Segmented
Results of Operations – Colombia for the Three and Nine Months Ended September
30, 2009 compared to the Results for the Three and Nine Months Ended September
30, 2008
For the
three months ended September 30, 2009, income before
income taxes from Colombia amounted to $8.0 million compared to income
before taxes of $30.0 million recorded for the same period in 2008. This is
mainly the result of a $19.8 million foreign exchange loss, of which $20.0
million is an unrealized non-cash foreign exchange loss, primarily due to the
translation of deferred taxes recorded on the purchase of Solana, and a $27.5
million increase in DD&A, primarily a result of the amortization of the fair
value of Solana’s property, plant and equipment recorded upon our acquisition of
Solana. These factors were partially offset by higher revenues. The results for
the first nine months of 2009 reflect income before income taxes of $5.4 million
compared to income before income taxes of $66.8 million recorded in the same
period in 2008. A foreign exchange loss of $33.0 million, of which $32.6 million
is an unrealized non-cash foreign exchange loss, coupled with a $77.2 million
increase in DD&A was only partially offset by increased
revenues. Higher operating expenses due to increased Colombian
production and increased general and administrative expenses from expanded
activities were also contributing factors to the reduced income before income
taxes in both periods.
For the
three months ended September 30, 2009, production of
crude oil and NGLs, net after royalties, increased by 233% to 1,107,265
barrels compared to 332,382 barrels for the same period in 2008. The
production for the first nine months amounted to 3,017,078 barrels compared to
806,382 barrels, an increase of 274% from the same period last year. The
incremental production volumes from Solana properties for the three and nine
months ended September 30, 2009 were 565,957 and 1,552,321 barrels of oil,
respectively. These production levels are after government royalties ranging
from 8% to 22.5% and third party royalties of 2% to 10%.
Gran
Tierra’s Colombian operating results for the three months ended September 30,
2009 are principally impacted by the inclusion of production from four new
development wells in the Costayaco field, including Solana’s 50% share of
production from Costayaco, and Solana’s 35% share of production from Juanambu –
1 in the Guayuyaco Block. In the third quarter of 2008, Colombia production
included production from Costayaco – 1, – 2, – 3, and Juanambu – 1 along with
production from the Santana Block.
Our
production in 2009 and 2008 was impacted by political and economic factors in
Colombia. In the second and third quarter of 2009, sections of the Ecopetrol
operated Trans Andean Pipeline were damaged, which temporarily reduced our
deliveries to Ecopetrol. In the first and second quarter of 2008, sections
of the Ecopetrol operated Trans Andean Pipeline were disrupted, which
temporarily reduced our deliveries to Ecopetrol, resulting in higher than
average Colombia crude oil inventories. Ecopetrol was able to restore deliveries
within one to two weeks. On November 24, 2008, we temporarily suspended
production operations in the Costayaco and Juanambu oil fields. This was as a
result of a declaration of a state of emergency and force majeure by Ecopetrol,
due to a general strike in the region where our operations are located. On
January 12, 2009, crude oil transportation resumed in southern Colombia as a
result of the lifting of the strike at the Orito facilities operated by
Ecopetrol.
26
As a
result of these factors, deliveries to Ecopetrol in 2009 were reduced to
approximately 3,800 BOPD, net after royalties, for 32 days between July and
August 2009, and reduced to approximately 2,200 BOPD, net after royalties, for
14 days in June, and we were shut in for the first 10 days of January. During
the first quarter of 2008, deliveries to Ecopetrol were reduced to approximately
1,900 BOPD, net after royalties, for 18 days and in the second quarter of 2008
deliveries were reduced to approximately 2,300 BOPD, net after royalties, for 14
days.
Revenue and
interest were negatively impacted by a decline in net realized crude
oil prices in 2009 compared to 2008. The average net realized prices for crude
oil, which are based on WTI prices, decreased by 43% to $64.47 per barrel for
the three months ended September 30, 2009 compared to the same period last year.
For the first nine months of this year, the average realized price decreased by
53% to $51.73 per barrel from $108.99 for the same period last year. However,
substantially increased production resulted in our revenue and interest from
Colombia for the three and nine months ended September 30, 2009 increasing by
89% to $71.4 million, and by 78% to $156.6 million, respectively, from the
comparable prior year periods.
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
percent of the field production revenue over an inflation adjusted trigger
point. That trigger point for Gran Tierra is $30.22 for 2009. Production revenue
for this calculation is based on production volumes net of other government
royalty volumes. Average government royalties at Costayaco with gross production
of 19,000 BOPD and $70 WTI per barrel are approximately 24.8%, including the
additional government royalty of approximately 17.0%. The National
Hydrocarbons Agency sliding scale royalty at 19,000 BOPD is approximately 9.4%
and this royalty is deductible prior to calculating the additional government
royalty.
Operating
expenses for the three months ended September 30, 2009 increased to $7.2
million from $2.5 million in the same period last year. For the nine months
ended September 30, 2009 operating expenses increased to $20.3 million compared
to $6.3 million in the same period in 2008. The increased operating expenses
resulted from the increase in production and the inclusion of the Solana
operations acquired on November 14, 2008. However, on a per barrel basis,
operating expenses for the third quarter of 2009 declined to $6.54 compared to
$7.38 incurred for the same period last year ($6.72 for the first nine months of
2009 versus $7.84 in the same period last year) reflecting the reduction of
fixed operating costs per barrel as total production increased.
For the
three and nine months ended September 30, 2009, DD&A
expense increased to $33.6 million from $6.1 million and to $90.6 million from
$13.4 million, respectively, compared to the same periods in 2008. Increased
production levels coupled with a higher depletable cost base resulting from the
Solana acquisition, partially offset by higher crude oil reserve levels,
accounted for the increase in DD&A expense. The incremental DD&A
expense recorded as a result of the Solana acquisition was $26.9 million and
$72.4 million, respectively, for the three and nine months ended September 30,
2009. On a per boe basis, the DD&A expense in Colombia increased by 65% to
$30.37 for the third quarter and by 80% to $29.99 for the first nine months of
2009 compared with the comparable periods last year due to the higher depletable
cost base reflecting the Solana properties recorded at fair value upon
acquisition, partially offset by increased proved reserves.
Higher
general and administrative expenses incurred to manage the increased level of
development and operating activities and, the Solana acquired properties, and
increased stock-based compensation expense resulted in G&A
expense increasing to $2.8 million for the three months ended September 30, 2009
from $0.7 million incurred for the same period in 2008. For the nine months
ended September 30, 2009, G&A increased to $7.4 million from $3.2 million
incurred for the first nine months of 2008, for the same reasons cited above. On
a per barrel basis, G&A expense increased by 21% to $2.51 from $2.08 for the
third quarter of 2009 compared with the same period in 2008 due to relatively
higher capitalized G&A recoveries recorded in the third quarter of 2008
versus the current quarter. For the nine months ended September 30, 2009,
G&A expense per boe decreased by 38% to $2.45 from $3.98 for the first nine
months of 2008, due to higher production.
The foreign exchange
loss of $19.8 million for the three months ended September 30, 2009
includes an unrealized non-cash foreign exchange loss of $19.6 million which
resulted from the translation of a deferred tax liability recognized on the
purchase of Solana. For the nine months ended September 30, 2009, the foreign
exchange loss was $33.0 million, of which $32.2 million is an unrealized
non-cash foreign exchange loss on translation of deferred taxes 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 $70,000 for each one peso decrease in the exchange rate of the
Colombian peso to one U.S. dollar.
Capital
Program - Colombia
Gran
Tierra’s focus for the third quarter of 2009, in addition to undertaking
additional oil exploration efforts to further define the potential of our
acreage in Colombia, was to continue with the development of the Costayaco field
to increase our production. In support of this strategy, our capital
expenditures in Colombia amounted to $17.0 million and $58.4 million,
respectively, for the three and nine months ended September 30, 2009.
27
Segmented Capital Expenditures - Colombia
Block and Activity
|
Three Months Ended
|
Nine Months Ended
|
||||||
(Millions
of U.S. Dollars)
|
September 30, 2009
|
September 30, 2009
|
||||||
Chaza
- drilled and tested Costayaco -6, -7, -8, -9, commenced drilling of
Costayaco -10, commenced 2D seismic program, installed facilities and
equipment
|
$ | 11.6 | $ | 33.4 | ||||
Rio
Magdalena - completion and long term testing of Popa-2
well
|
1.4 | 2.7 | ||||||
Guachiria
- completed acquisition of 115 square kilometers of 3D
seismic
|
- | 1.1 | ||||||
Guachiria
Norte Block - drilling of the Puinaves -2 exploration well, which was
dry
|
- | 5.8 | ||||||
Guachiria
Sur - completed acquisition of 115 square kilometers of 3D
seismic
|
- | 3.7 | ||||||
Garibay
- completed acquisition of 110 square kilometers of 3D
seismic
|
- | 2.6 | ||||||
Azar
- commencement of 2D and 3D seismic programs
|
1.0 | 1.8 | ||||||
San
Pablo - commencement of 3D seismic programs
|
1.2 | 2.2 | ||||||
Leasehold
improvements
|
0.3 | 2.0 | ||||||
Capitalized
G&A and other
|
1.5 | 3.1 | ||||||
Segmented
Capital Expenditures - Colombia
|
$ | 17.0 | $ | 58.4 |
For
comparison, during the three months ended September 30, 2008, we spent $5.1
million on capital projects and for the nine month period ended September 30,
2008 we spent $18.3 million on capital projects.
Segmented
Capital Expenditures - Colombia
Block
and Activity
|
Three
Months Ended
|
Nine
Months Ended
|
||||||
(Millions
of U.S. Dollars)
|
September
30, 2008
|
September
30, 2008
|
||||||
Chaza
- drilled and tested Costayaco -2, -3, -4, -5, commenced drilling of
Costayaco -6, and facilities and equipment
|
$ | 3.8 | $ | 15.4 | ||||
Guayayaco
- Juanambu facilities
|
- | 0.5 | ||||||
Azar
- commencement of 2D seismic programs
|
0.3 | 0.5 | ||||||
Leasehold
improvements
|
- | 0.7 | ||||||
Capitalized
G&A and other
|
1.0 | 1.2 | ||||||
Segmented
Capital Expenditures - Colombia
|
$ | 5.1 | $ | 18.3 |
Due to
the high cost to transport oil produced from the Guachiria Blocks in Llanos
Basin, acquired from Solana in Colombia, production was shut in February
2009. In April 2009, the company signed an asset purchase and sale agreement
with a third party for Gran Tierra's interests in the Guachiria Norte,
Guachiria, and Guachiria Sur Blocks. Principal terms included consideration
of $7.0 million between the third party and Gran Tierra's subsidiary,
Solana, comprising an initial cash payment of $4.0 million at closing, followed
by 15 monthly installments of $200,000 each beginning June 1, 2009 and extending
through August 3, 2010, less settlement of outstanding amounts. The sale closed
on April 16, 2009 and Gran Tierra recorded net
proceeds of $6.3 million. Gran Tierra retained a 10% overriding royalty interest
on the Guachiria Sur Block, which, in the event of a discovery, is designed to
reimburse 200% of our costs for previously acquired seismic data.
28
Segmented
Results – Argentina
Segmented Results of
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
||||||||||||||||||||||
Operations - Argentina
(Thousands
of U.S. Dollars)
|
2009
|
2008
|
% Change
|
2009
|
2008
|
% Change
|
||||||||||||||||||
Oil
and natural gas sales
|
$ | 3,786 | $ | 2,349 | 61 | $ | 10,349 | $ | 5,982 | 73 | ||||||||||||||
Interest
|
34 | 8 | 325 | 84 | 18 | 367 | ||||||||||||||||||
3,820 | 2,357 | 62 | 10,433 | 6,000 | 74 | |||||||||||||||||||
Operating
expenses
|
1,856 | 2,034 | (9 | ) | 4,738 | 4,370 | 8 | |||||||||||||||||
Depletion,
depreciation and accretion
|
1,538 | 593 | 159 | 4,671 | 1,716 | 172 | ||||||||||||||||||
General
and administrative expenses
|
546 | 497 | 10 | 1,511 | 1,451 | 4 | ||||||||||||||||||
Foreign
exchange (gain) loss
|
(510 | ) | 175 | (391 | ) | 90 | 44 | 105 | ||||||||||||||||
3,430 | 3,299 | 4 | 11,010 | 7,581 | 45 | |||||||||||||||||||
Segment
income (loss) before income taxes
|
$ | 390 | $ | (942 | ) | (141 | ) | $ | (577 | ) | $ | (1,581 | ) | (64 | ) | |||||||||
Production,
Net of Royalties
|
||||||||||||||||||||||||
Oil
and NGL's ("bbl") (1) (2)
|
83,689 | 53,484 | 56 | 256,519 | 147,575 | 74 | ||||||||||||||||||
Average
Prices
|
||||||||||||||||||||||||
Oil
and NGL's ("per bbl")
|
$ | 45.24 | $ | 43.91 | 3 | $ | 40.34 | $ | 40.54 | - | ||||||||||||||
Segmented
Results of
Operations
("per boe")
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 45.24 | $ | 43.91 | 3 | $ | 40.34 | $ | 40.54 | - | ||||||||||||||
Interest
|
0.41 | 0.15 | 173 | 0.33 | 0.12 | 175 | ||||||||||||||||||
45.65 | 44.06 | 4 | 40.67 | 40.66 | - | |||||||||||||||||||
Operating
expenses
|
22.18 | 38.03 | (42 | ) | 18.47 | 29.61 | (38 | ) | ||||||||||||||||
Depletion,
depreciation and accretion
|
18.38 | 11.09 | 66 | 18.21 | 11.63 | 57 | ||||||||||||||||||
General
and administrative expenses
|
6.52 | 9.29 | (30 | ) | 5.89 | 9.83 | (40 | ) | ||||||||||||||||
Foreign
exchange (gain) loss
|
(6.09 | ) | 3.27 | (286 | ) | 0.35 | 0.30 | 17 | ||||||||||||||||
40.99 | 61.68 | (34 | ) | 42.92 | 51.37 | (16 | ) | |||||||||||||||||
Segment
income (loss) before income taxes
|
$ | 4.66 | $ | (17.62 | ) | (126 | ) | $ | (2.25 | ) | $ | (10.71 | ) | (79 | ) |
(1)
NGL volumes are converted to boe on a one-to-one basis with
oil.
|
(2)
Production represents production volumes adjusted for inventory
changes.
|
Segmented
Results of Operations – Argentina for the Three and Nine Months Ended September
30, 2009 compared to the Results for the Three and Nine Months Ended September
30, 2008
For the
three months ended September 30, 2009 the pre-tax
income from Argentina was $0.4 million compared to a pre-tax loss of $0.9
million recorded in the same period in 2008. The increase resulted
from higher production levels offset partially by increased depletion. For the
nine months ended September 30, 2009, the pre-tax loss was $0.6 million compared
to $1.6 million of pre-tax loss recorded in the same period last year, due to
the same factors cited above.
Crude oil and NGL
production, net after 12% royalties, increased to 83,689 barrels for the
three months ended September 30, 2009 compared to 53,484 barrels for the same
period in 2008. For the nine months ended September 30, 2009, production levels
increased by 74% to 256,519 barrels compared to 147,575 barrels produced in the
same period in 2008. The increase resulted from the successful
completion and testing of the Proa – 1 exploration well in the Surubi Block
in the third quarter of 2008 with sales commencing in the fourth quarter of the
year.
Due to
the local regulatory regimes, the price we currently receive for production from
our blocks is approximately $43 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 September
30, 2009. 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.
29
With
regulated crude oil prices, the change in our revenues
over the same quarter in 2008 has been reflective of changes in our production
levels. Revenues of $3.8 million generated in the three months ended September
30, 2009 compares to $2.3 million for the same period in 2008. For the nine
months ended September 30, 2009, revenue levels were $10.3 million compared to
$6.0 million in the comparable prior period.
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 September 30, 2009, decreased
slightly to $1.9 million ($22.18 per boe) compared to $2.0 million ($38.03 per
boe) incurred in the same quarter last year. Operating expenses for the first
three quarters of 2009 marginally increased to $4.7 million ($18.47 per boe)
compared to $4.4 million ($29.61 per boe) for the same period a year ago. Higher
production volumes from Proa – 1 in the Surubi Block, in both comparative
periods, resulted in the significant reductions in the operating costs per boe
basis.
DD&A
expense for the three and nine months ended September 30, 2009 was $1.5 million
and $4.7 million, respectively, an increase from the $0.6 million and $1.7
million recorded in the same periods of 2008, respectively. On a per boe basis,
DD&A for the three and nine months ended September 30, 2009 increased to
$18.38 and $18.21, respectively, from $11.09 and $11.63 recorded in the same
periods last year. The impact of higher production levels and lower proved
reserves was partially offset by a decreasing proved depletable cost base. This
decreasing proved depletable cost base is a result of reduced development
expenditures in Argentina.
Capital
Program - Argentina
Capital
expenditures for the three months ended September 30, 2009, amounted to $1.9
million bringing the total expenditures in the region for the first nine months
of 2009 to $3.2 million. The capital expenditures for the three and nine months
ended September 30, 2009 mainly relate to workovers, facility construction, and
the acquisition of seismic. Capital expenditures in Argentina for the three
months ended September 30, 2008, were $6.4 million ($8.9 million for the nine
months ended September 30, 2008). The expenditures incurred in Argentina during
the first nine month period of 2008 included $7.6 million drilling expense for
the exploration well, Proa-1, in the Surubi Block. Other capital
expenditures for the nine months ended September 30, 2008, were facilities
upgrade costs of $0.3 million in the Palmar Largo area, exploration land lease
costs and capitalized G&A including non-cash stock based compensation
expense.
Segmented
Results – Corporate
Segmented Results of |
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
||||||||||||||||||||||
Operations –
Corporate
(Thousands
of U.S. Dollars)
|
2009
|
2008
|
%
Change
|
2009
|
2008
|
%
Change
|
||||||||||||||||||
Interest
|
$ | 118 | $ | 111 | 6 | $ | 388 | $ | 132 | 194 | ||||||||||||||
Operating
expenses
|
1 | 26 | (96 | ) | 33 | 71 | (54 | ) | ||||||||||||||||
Depletion,
depreciation and accretion
|
78 | 35 | 123 | 230 | 96 | 140 | ||||||||||||||||||
General
and administrative expenses
|
3,753 | 2,847 | 32 | 10,319 | 8,147 | 27 | ||||||||||||||||||
Derivative
financial instruments (gain) loss
|
(77 | ) | (4,475 | ) | (98 | ) | 207 | 2,987 | (93 | ) | ||||||||||||||
Foreign
exchange (gain) loss
|
(435
|
) | (151 | ) | 188 | (723 | ) | (188 | ) | 285 | ||||||||||||||
3,320 | (1,718 | ) | (293 | ) | 10,066 | 11,113 | (9 | ) | ||||||||||||||||
Segment
income (loss) before income taxes
|
$ | (3,202 | ) | $ | 1,829 | (275 | ) | $ | (9,678 | ) | $ | (10,981 | ) | (12 | ) |
30
Segmented
Results of Operations - Corporate
In
addition to the expenditures associated with the maintenance of Gran Tierra’s
headquarters in Calgary, Alberta, Canada, and cost of compliance and reporting
under the securities regulation, the results of the Corporate Segment include
the results of our initial operations in Peru and Brazil.
G&A
Expenses
The
increase in G&A expenses between both comparative periods in the prior year
was mainly attributable to increased staff and higher stock based compensation
expense due to increased stock option grants.
(Gain) Loss
from Derivative Financial Instruments
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
(Thousands of U.S. Dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Realized
financial derivative (gain) loss
|
$ | - | $ | 1,052 | $ | (87 | ) | $ | 2,745 | |||||||
Unrealized
financial derivative (gain) loss
|
(77 | ) | (5,527 | ) | 294 | 242 | ||||||||||
Derivative
financial instruments (gain) loss
|
$ | (77 | ) | $ | (4,475 | ) | $ | 207 | $ | 2,987 |
As at September
30,
|
As at December
31,
|
|||||||
Assets
(Liabilities)
|
2009
|
2008
|
||||||
Derivative
financial instruments
|
$ | (61 | ) | $ | 233 |
In
accordance with the terms of the credit facility with Standard Bank Plc, in
February of 2007 we entered into a costless collar financial derivative contract
for crude oil based on WTI price, with a floor of $48.00 and a ceiling of
$80.00, for a three year period, for 400 barrels per day from March 2007 to
December 2007, 300 barrels per day from January 2008 to
December 2008, and 200 barrels per day from January 2009 to
February 2010.
For the
three and nine months ended September 30, 2009, we recorded a gain of $0.1
million and a loss of $0.2 million, respectively. This compares to a gain of
$4.5 million, and a $3.0 million loss from derivative financial instruments, for
the three and nine months ended September 30, 2008, respectively. These gains
and loses are based on the effects of changing WTI crude oil price, and forward
price curves used to fair value the costless collar of the respective period
ends.
Foreign
Exchange Loss (Gain)
The
foreign exchange loss (gain) results from the translation of foreign currency
denominated transactions to U.S. Dollars.
Capital
Program – Corporate
The
capital expenditures for the Corporate Segment during the three months ended
September 30, 2009 were $0.2 million, bringing the total expenditures for the
first nine months of 2009 to $1.8 million. The 2009 year-to-date
capital expenditures for the Corporate Segment included expenditures of $1.5
million for Peru on our exploration Blocks 122 and 128. The costs incurred
mainly related to drilling feasibility and geological studies on the blocks. For
comparison, during the third quarter of 2008, capital expenditures of $3.1
million ($5.1 million for the nine months ended September 30, 2008) related
mainly to acquisition of technical data through aeromagnetic-gravity studies in
Peru, which began in 2007 and was continued into 2008.
Liquidity
and Capital Resources
At
September 30, 2009, we had cash and cash equivalents of $151.6 million compared
to $176.8 million at December 31, 2008. We believe that our cash position and
access to unutilized credit facilities and no debt will provide us with
sufficient liquidity to meet our strategic objectives and fund our planned
capital program for at least the next 12 months. In accordance with our
investment policy, cash balances are invested only in United States or Canadian
government backed federal, provincial or state securities with the highest
credit ratings and short term liquidity.
31
Effective
February 28, 2007, we entered into a credit facility with Standard Bank
Plc. The facility has a three-year term which may be extended by agreement
between the parties. The borrowing base was the present value of our petroleum
reserves of a subsidiary, Gran Tierra Colombia, up to maximum of
$50 million. We recently completed negotiations with Standard Bank Plc to
increase the maximum amount of the credit facility to $200
million. Final documents were signed on August 24,
2009. The initial borrowing base is $7 million and the borrowing
base can be re-determined semi-annually based on reserve evaluation reports. As
a result of Standard Bank Plc’s review of Gran Tierra’s 2008 Independent Reserve
Audit, we have the capacity to increase the borrowing base to $120 million under
the revised facility; however, this has not been pursued further as the
additional borrowing base is not required at this time. The facility includes a
letter of credit sub-limit of $5 million. Amounts drawn down under the facility
bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is
charged on the un-drawn amount of the borrowing base. The facility is secured
primarily by the assets of Gran Tierra Colombia and Solana Petroleum Exploration
(Colombia) Ltd. Under the terms of the facility, Gran Tierra is required to
maintain and is in compliance with specified financial and operating covenants.
Gran Tierra was required to enter into a derivative instrument for the purpose
of obtaining protection against fluctuations in the price of oil in respect of
at least 50% of the June 30, 2006 Independent Reserve Evaluation Report
projected aggregate net share of Colombian production after royalties for the
three year term of the Facility. As at September 30, 2009, no amounts have
been drawn-down under this facility.
Following
the acquisition of Solana, effective November 14, 2008, Gran Tierra obtained
access to an additional credit facility with BNP Paribas. The
facility had a maturity date of December 20, 2010. The borrowing base
was $26 million, based on the current value of petroleum reserves of the
subsidiary, Solana Petroleum Exploration (Colombia) Ltd., up to a maximum of
$100 million. This facility was cancelled effective August 4, 2009 as a result
of the successful negotiations with Standard Bank to increase the maximum amount
available under that facility.
The
following provides an analysis of our cash in-flows and out-flows during the
nine months ended September 30, 2009 and 2008:
Cash
Flows
During
the nine months ended September 30, 2009, our cash and cash equivalents
decreased by $25.2 million as cash inflows from operations of $35.0 million and
from financing activities of $2.3 million were more than offset by cash outflows
for investing activities of $62.4 million. Net cash provided by operating
activities was affected by the significant increase in crude oil production
offset by the decrease in prices as well as increases in receivables related to
oil sales.
During
the nine months ended September 30, 2008, our cash and cash equivalents
increased by $39.6 million due to cash inflows from operations of $44.4 million,
cash outflows from investing activities of $26.6 million and cash inflows from
financing activities of $21.7 million. Net cash provided by operating activities
was affected by the significant increase in crude oil production and prices
offset by the increase in receivables related to oil sales. Net cash provided by
financing activities represented proceeds from the issuance of common shares
upon exercise of warrants and stock options.
Off-Balance
Sheet Arrangements
As at
September 30, 2009, we had no off-balance sheet arrangements.
Contractual
Obligations
Gran
Tierra holds four categories of operating leases, namely office, compressor,
vehicle and housing. Future lease payments and other contractual obligations at
September 30, 2009 are as follows:
As at September 30, 2009
|
||||||||||||||||||||
Payments Due in Period
|
||||||||||||||||||||
Contractual Obligations
(Thousands
of U.S. Dollars)
|
Total
|
Less than 1
Year
|
1 to 3
years
|
3 to 5
years
|
More than 5
years
|
|||||||||||||||
Operating
leases
|
$ | 5,191 | $ | 2,161 | $ | 2,706 | $ | 324 | $ | - | ||||||||||
Drilling,
Completion, Facility Construction and Oil Transportation
Services
|
20,426 | 18,257 | 2,169 | - | - | |||||||||||||||
Total
|
$ | 25,617 | $ | 20,418 | $ | 4,875 | $ | 324 | $ | - |
Contractual
commitments have increased $19.4 million from December 31, 2008 as a result of
entering into third party facility construction, oil transportation and drilling
rig commitment contracts in Colombia.
32
Related
Party Transactions
In
connection with the Solana acquisition, we acquired additional office space of
4,441 square feet used by Solana as its headquarters in Calgary. The lease
payments under the lease are $9,700 per month and operating and other expenses
are approximately $4,300 per month. The lease expires on April 30,
2014. On February 1, 2009, we entered into a sublease for that
office space with a company, of which two of Gran Tierra’s directors are
shareholders and directors. The term of the sublease runs from February 1,
2009 to August 31, 2011 and the sublease payment is $7,600 per month plus
approximately $3,900 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 negatively impacted by the continuing fluctuations in crude
oil prices. Crude oil prices are volatile and unpredictable and are influenced
by concerns about financial markets and the impact of the downturn in the
worldwide economy on oil demand growth. However, based on projected production,
prices, costs and our current liquidity position, we believe that our current
operations and capital expenditure program can be maintained from cash flow from
existing operations, cash on hand, and our credit facilities, barring unforeseen
events or a further severe downturn in oil and gas prices. Should our operating
cash flow decline, we would examine measures such as reducing our capital
expenditure program, issuance of debt, disposition of assets, or issuance of
equity.
The
credit markets, including the commercial paper markets in the United States,
have experienced adverse conditions. Although we have not been materially
impacted by these conditions, continuing volatility in the credit markets may
increase costs associated with renewing or increasing our credit facilities, or
affect our, or third parties we seek to do business with, ability to access
those markets.
Our
future growth and acquisitions may depend on our ability to raise additional
funds through equity and debt markets. Increases in the borrowing base under our
credit facilities are dependent on our success in increasing oil and gas
reserves and on future oil prices. Additional funds will be provided to us if
holders of our warrants to purchase common shares decide to exercise the
warrants. Should we be required to raise debt or equity financing to fund
capital expenditures or other acquisition and development opportunities, such
funding may be affected by the market value of our common stock. If the price of
our common stock declines, our ability to utilize our stock to raise capital may
be negatively affected. Also, raising funds by issuing stock or other equity
securities would further dilute our existing stockholders, and this dilution
would be exacerbated by a decline in our stock price. Any securities we issue
may have rights, preferences and privileges that are senior to our existing
equity securities. Borrowing money may also involve further pledging of some or
all of our assets that are not currently pledged under our existing credit
facilities.
2009
Work Program and Capital Expenditure Program
Gran
Tierra’s 2009 work program is intended to create both growth and value in our
existing assets through increasing our reserves and production, while retaining
the financial flexibility, with a strong cash position and no debt, to pursue
acquisition opportunities.
We intend
to continue to explore our large land position encompassing 5.6 million net
acres through a program that anticipates two exploration wells in Colombia in
the fourth quarter of 2009, as well as multiple seismic programs in Colombia in
preparation for a very active exploration drilling program in 2010.
We expect
our capital expenditure program for 2009 will be fully funded from cash flow and
cash on hand. We will continue to monitor our capital spending for the remainder
of 2009. We have the flexibility to defer or cancel portions of our
capital program in response to a drop in WTI from the average of approximately
$68 per barrel of oil in the third quarter of 2009.
Outlook
– Colombia
Gran
Tierra evaluated the optimum production plateau for the Costayaco field taking
into consideration reserves, reservoir performance, good operating practice, and
net present value of the project. Accordingly, in the second quarter of 2009, we
revised the planned production plateau for Costayaco to 19,000 BOPD
gross. This production plateau was achieved ahead of schedule in
August. We are expecting to maintain an average consolidated company
production rate between 14,000 to 16,000 BOPD net after royalty for the balance
of 2009, excluding the effect of pipeline interruptions.
New
infrastructure construction at Costayaco is continuing, including facilities,
crude gathering lines, water lines, upgrading a pumping station, and storage
batteries. A water handling, processing, and injection facility for Costayaco is
also planned. The last development well planned for the Costayaco filed in 2009,
Costayaco – 10, was spudded on October 5.
In
addition to the ongoing Costayaco field development activities, one exploration
well, the Rio Mocca (Dantayaco-1) prospect to the west of Costayaco field, is
currently anticipated for the remainder of 2009 in the Chaza Block. A second
prospect, the Moqueta prospect, is planned to be drilled in early 2010. In
addition, we have begun the process to relinquish the San Pablo Block in the
Llanos basin.
33
In June
2009, we signed three Exploration and Exploitation contracts with the National
Hydrocarbon Agency totaling 235,264 acres in which we have a 100% working
interest. The Piedemonte Norte Block, encompassing 78,742 acres, lies southwest
of the Chaza Block where the Costayaco field is located. The
Piedemonte Sur Block, encompassing approximately 73,898 acres, is located
immediately west of the Orito Field, the largest oil field in the Putumayo
Basin. Further south, the Rumiyaco Block encompasses 82,624 acres in
the central Putumayo Basin. We expect these new blocks to be the focus of
exploration drilling efforts by Gran Tierra in 2010.
Total
2009 capital expenditures planned for Colombia is $87 million.
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. The Nacatimbay Block has been relinquished. The workover
program for 2009 has been largely completed. We have initiated testing of the
VM-1001 gas well in the Valle Marado Block. Production in Argentina is expected
to be maintained at approximately 1,000 BOPD, net after royalty, in
2009.
Total
2009 capital expenditures planned for Argentina is $5 million.
Outlook
– Peru
Gran
Tierra has expanded its environmental impact assessment on Blocks 122 and 128 in
the Marañon Basin of northeastern Peru to include stratigraphic test drilling
which is expected to be undertaken in 2010. The environmental impact
assessments for Block 122 and Block 128 have been submitted to the Peruvian
government for review and approval.
These
assessments are in preparation for a 500 kilometer 2D seismic survey expected to
be initiated in the first 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 2010. In addition, a pre-feasibility
engineering field development study was completed in the first half of 2009 to
assist with planning in the event a commercial discovery is made in
2010.
Total
2009 capital expenditures planned for Peru is $2 million.
Critical
Accounting Estimates
The
preparation of financial statements under generally accepted accounting
principles (“GAAP”) in the United States requires management to make estimates,
judgments and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
On a regular basis we evaluate our assumptions, judgments and estimates. We also
discuss our critical accounting estimates with the Audit Committee of the Board
of Directors.
We
believe that the assumptions, judgments and estimates involved in the accounting
for oil and gas accounting and impairment, reserves determination, asset
retirement obligation, share-based payment arrangements, goodwill impairment,
warrants and income taxes have the greatest potential impact on our condensed
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.
Historically, our assumptions, judgments and estimates relative to our critical
accounting estimates have not differed materially from actual
results.
Our
critical accounting estimates are disclosed in Item 7 of our 2008 Annual Report
on Form 10-K, filed with the Securities and Exchange Commission on February 27,
2009, 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, we entered into a costless collar
financial derivative contract for crude oil based on WTI price, with a floor of
$48.00 and a ceiling of $80.00, for a three year period, for 400 barrels per day
from March 2007 to December 2007, 300 barrels per day from
January 2008 to December 2008, and 200 barrels per day from
January 2009 to February 2010. At September 30, 2009, this costless
collar represented a liability of $61,000, compared to an asset of $233,000 at
December 31, 2008. A hypothetical 10% increase in WTI price on September 30,
2009 would cause the value to increase by approximately $95,000, and a
hypothetical 10% decrease in WTI price on September 30, 2009 would cause the
value to decrease by approximately $57,000. This compares to a
hypothetical 10% increase in WTI price on December 31, 2008 would cause the
value to decrease by approximately $229,000, and a hypothetical 10% decrease in
WTI price on December 31, 2008 would cause the value to increase by
approximately $345,000.
34
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. However,
if we draw down amounts under our credit facilities with Standard Bank Plc we
will incur interest rate risk with respect to the amounts drawn down and
outstanding. Our investment objectives are focused on preservation of principal
and liquidity. By policy, we manage our exposure to market risks by limiting
investments to high quality bank issuers at overnight rates, 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. In Colombia, we receive 75% of
oil revenues in U.S. dollars and 25% in Colombian pesos at current exchange
rates. The majority of our capital expenditures in Colombia are in U.S. dollars
and the majority of local office costs are in local currency. As a result, the
75%/25% allocation between U.S. dollar and peso denominated revenues is
approximately balanced between U.S. and peso expenditures, providing a natural
currency hedge. In Argentina, reference prices for oil are in U.S. dollars and
revenues are received in Argentine pesos according to current exchange rates.
The majority of capital expenditures within Argentina have been in U.S. dollars
with local office costs generally in pesos. While we operate in South America
exclusively, the majority of our spending since our inauguration has been for
acquisitions. The majority of these acquisition expenditures have been valued
and paid in U.S. dollars.
Additionally,
foreign exchange gains/losses result from the fluctuation of the U.S. dollar to
the Colombian peso due to our deferred tax liability, a monetary liability,
which is mainly denominated in the local currency of the Colombian foreign
operations. As a result, a foreign exchange gain/loss must be calculated on
conversion to the U.S. dollar functional currency. A strengthening in the
Colombian peso against the U.S. dollar results in foreign exchange losses,
estimated at $70,000 for each one peso decrease in the exchange rate of the
Colombian peso to one U.S. dollar.
ITEM 4. - CONTROLS AND
PROCEDURES
(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) that
are designed to provide reasonable assurance that information required to be
disclosed by a company in the reports that it files under the Exchange Act is
recorded, processed, summarized, and reported within the required time
periods.
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 September 30,
2009 to ensure 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
Securities and Exchange Commission 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.
Changes
in Internal Control over Financial Reporting
During
the quarter ended on September 30, 2009, 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, 2008, filed with the Securities and
Exchange Commission on February 27, 2009.
35
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, 2008, filed with the
Securities and Exchange Commission on February 27, 2009, are set forth below,
and the risks that reflect substantive changes from the risk factors in the Form
10-K are designated by an asterisk (*).We removed the last risk factor appearing
in our Annual Report on Form 10-K relating to the lack of sufficient
authorized but unissued shares, because we recently amended our Articles of
Incorporation increasing the authorized number of shares of common stock by 270
million shares.
Risks Related to Our
Business
Our Lack of
Diversification Will Increase the Risk of an Investment in Our Common
Stock.
Our
business focuses on the oil and gas industry in a limited number of properties,
initially in Colombia, Argentina, and Peru, with the intention of expanding
elsewhere into Brazil and other countries. Larger companies have the ability to
manage their risk by diversification. However, we lack diversification, in terms
of both the nature and geographic scope of our business. As a result, factors
affecting our industry or the regions in which we operate will likely impact us
more acutely than if our business was more diversified.
We May Be Unable
to Obtain Additional Capital That We Will Require to Implement Our Business
Plan, Which Could Restrict Our Ability to
Grow.
We expect
that our cash balances and cash flow from operations and existing credit
facilities will be sufficient only to fund our currently planned activities. We
will require additional capital to continue to operate our business beyond our
current planned activities and to expand our exploration and development
programs to additional properties. We may be unable to obtain additional capital
required.
When we
require additional capital we plan to pursue sources of capital through various
financing transactions or arrangements, including joint venturing of projects,
debt financing, equity financing or other means. We may not be successful in
locating suitable financing transactions in the time period required or at all,
and we may not obtain the capital we require by other means. The current
situation in world capital markets has made it increasingly difficult for
companies to raise funds. If we do succeed in raising additional
capital, future financings may be dilutive to our stockholders, as we could
issue additional shares of common stock or other equity to investors in future
financing transactions. In addition, debt and other mezzanine financing may
involve a pledge of assets and may be senior to interests of equity holders. We
may incur substantial costs in pursuing future capital financing, including
investment banking fees, legal fees, accounting fees, securities law compliance
fees, printing and distribution expenses and other costs. We may also be
required to recognize non-cash expenses in connection with certain securities we
may issue, such as convertibles and warrants, which will adversely impact our
financial condition.
Our
ability to obtain needed financing may be impaired by factors such as the
capital markets (both generally and in the oil and gas industry in particular),
the location of our oil and natural gas properties in South America and prices
of oil and natural gas on the commodities markets (which will impact the amount
of asset-based financing available to us) and/or the loss of key management.
Further, if oil and/or natural gas prices on the commodities markets decrease,
then our revenues will likely decrease, and such decreased revenues may increase
our requirements for capital. Some of the contractual arrangements governing our
exploration activity may require us to commit to certain capital expenditures,
and we may lose our contract rights if we do not have the required capital to
fulfill these commitments. If the amount of capital we are able to raise from
financing activities, together with our cash flow from operations, is not
sufficient to satisfy our capital needs (even to the extent that we reduce our
activities), we may be required to cease our operations.
Our Business May
Suffer If We Do Not Attract and Retain Talented
Personnel.
Our
success will depend in large measure on the abilities, expertise, judgment,
discretion, integrity and good faith of our management and other personnel in
conducting the business of Gran Tierra. We have a small management team
consisting of Dana Coffield, our President and Chief Executive Officer, Martin
Eden, our Vice President, Finance and Chief Financial Officer, Shane O’Leary,
our Chief Operating Officer, Rafael Orunesu, our President of Gran Tierra
Argentina SA, Edgar Dyes, our President of Gran Tierra Colombia, and Julio
Moreira, our President of Gran Tierra Brazil. The loss of any of these
individuals or our inability to attract suitably qualified individuals to
replace any of them could materially adversely impact our business. We may also
experience difficulties in certain jurisdictions in our efforts to obtain
suitably qualified staff and retain staff that are willing to work in that
jurisdiction. We do not currently carry life insurance for our key
employees.
36
Our
success depends on the ability of our management and employees to interpret
market and geological data successfully and to interpret and respond to
economic, market and other business conditions in order to locate and adopt
appropriate investment opportunities, monitor such investments and ultimately,
if required, successfully divest such investments. Further, our key personnel
may not continue their association or employment with Gran Tierra and we may not
be able to find replacement personnel with comparable skills. If we are unable
to attract and retain key personnel, our business may be adversely
affected.
Unanticipated
Problems in Our Operations May Harm Our Business and Our
Viability.
If our
operations in South America are disrupted and/or the economic integrity of these
projects is threatened for unexpected reasons, our business may experience a
setback. These unexpected events may be due to technical difficulties,
operational difficulties which impact the production, transport or sale of our
products, geographic and weather conditions, business reasons or otherwise.
Prolonged problems may threaten the commercial viability of our operations.
Moreover, the occurrence of significant unforeseen conditions or events in
connection with our acquisition of operations in South America may cause us to
question the thoroughness of our due diligence and planning process which
occurred before the acquisitions, and may cause us to reevaluate our business
model and the viability of our contemplated business. Such actions and analysis
may cause us to delay development efforts and to miss out on opportunities to
expand our operations.
For
example, starting on November 21, 2008, we were forced to reduce production in
Colombia on a gradual basis, culminating on December 11, 2008 when we suspended
all production from the Santana, Guayuyaco and Chaza Blocks in the Putumayo
Basin. This temporary suspension of production operations was the
result of a declaration of a state of emergency and force majeure by Ecopetrol
due to a general strike in the region. In January 2009, the situation
was resolved and we were able to resume production and sales shipments. In the
second and third quarters of 2009, sections of the Ecopetrol operated Trans
Andean Pipeline were damaged, which temporarily reduced our deliveries to
Ecopetrol.
Local Legal and
Regulatory Systems in Which We Operate May Create Uncertainty Regarding Our
Rights and Operating Activities, Which May Harm Our Ability to do
Business.
We are a
company organized under the laws of the State of Nevada and are subject to
United States laws and regulations. The jurisdictions in which we operate our
exploration, development and production activities may have different or less
developed legal systems than the United States, which may result in risks such
as:
·
|
effective
legal redress in the courts of such jurisdictions, whether in respect of a
breach of law or regulation, or, in an ownership dispute, being more
difficult to obtain;
|
·
|
a
higher degree of discretion on the part of governmental
authorities;
|
·
|
the
lack of judicial or administrative guidance on interpreting applicable
rules and regulations;
|
·
|
inconsistencies
or conflicts between and within various laws, regulations, decrees, orders
and resolutions; and
|
·
|
relative
inexperience of the judiciary and courts in such
matters.
|
In
certain jurisdictions the commitment of local business people, government
officials and agencies and the judicial system to abide by legal requirements
and negotiated agreements may be more uncertain, creating particular concerns
with respect to licenses and agreements for business. These licenses and
agreements may be susceptible to revision or cancellation and legal redress may
be uncertain or delayed. Property right transfers, joint ventures, licenses,
license applications or other legal arrangements pursuant to which we operate
may be adversely affected by the actions of government authorities and the
effectiveness of and enforcement of our rights under such arrangements in these
jurisdictions may be impaired.
Strategic
Relationships Upon Which We May Rely are Subject to Change, Which May Diminish
Our Ability to Conduct Our Operations.
Our
ability to successfully bid on and acquire additional properties, to discover
reserves, to participate in drilling opportunities and to identify and enter
into commercial arrangements will depend on developing and maintaining effective
working relationships with industry participants and on our ability to select
and evaluate suitable properties and to consummate transactions in a highly
competitive environment. These realities are subject to change and may impair
Gran Tierra’s ability to grow.
To
develop our business, we endeavor to use the business relationships of our
management and board of directors to enter into strategic relationships, which
may take the form of joint ventures with other private parties or with local
government bodies, or contractual arrangements with other oil and gas companies,
including those that supply equipment and other resources that we will use in
our business. We may not be able to establish these strategic relationships, or
if established, we may not be able to maintain them. In addition, the dynamics
of our relationships with strategic partners may require us to incur expenses or
undertake activities we would not otherwise be inclined to in order to fulfill
our obligations to these partners or maintain our relationships. If we fail to
make the cash calls required by our joint venture partners in the joint ventures
we do not operate, we may be required to forfeit our interests in these joint
ventures. If our strategic relationships are not established or
maintained, our business prospects may be limited, which could diminish our
ability to conduct our operations.
37
In
addition, our partners may not be able to fulfill their obligations, which would
require us to either take on their obligations in addition to our own, or
possibly forfeit our rights to the area involved in the joint
venture. In cases where we are not the operator of the joint venture,
the success of the projects held under these joint ventures is substantially
dependent on our joint venture partners. The operator is responsible
for day to day operations, safety, environmental compliance and relationships
with government and vendors.
We have
various work obligations on our blocks that must be fulfilled or we could face
penalties, or lose our rights to those blocks if we do not fulfill our work
obligations. Failure to fulfill obligations in one block can also
have implications on the ability to operate other blocks in the country ranging
from delays in government process and procedure to loss of rights in other
blocks or in the country as a whole.
Competition in
Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our
Production May Impair Our Business.
The oil
and gas industry is highly competitive. Other oil and gas companies will compete
with us by bidding for exploration and production licenses and other properties
and services we will need to operate our business in the countries in which we
expect to operate. Additionally, other companies engaged in our line of business
may compete with us from time to time in obtaining capital from investors.
Competitors include larger, foreign owned companies, which, in particular, may
have access to greater resources than us, may be more successful in the
recruitment and retention of qualified employees and may conduct their own
refining and petroleum marketing operations, which may give them a competitive
advantage. In addition, actual or potential competitors may be strengthened
through the acquisition of additional assets and interests. In the event that we
do not succeed in negotiating additional property acquisitions, our future
prospects will likely be substantially limited, and our financial condition and
results of operations may deteriorate.
We May Not Be
Able To Effectively Manage Our Growth, Which May Harm Our
Profitability.
Our
strategy envisions expanding our business. If we fail to effectively manage our
growth, our financial results could be adversely affected. Growth may place a
strain on our management systems and resources. We must continue to refine and
expand our business development capabilities, our systems and processes and our
access to financing sources. As we grow, we must continue to hire, train,
supervise and manage new employees. We may not be able to:
·
|
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.
We May Have
Difficulty Transporting Our Production, Which Could Harm Our Financial
Condition.
To sell
the oil and natural gas that we are able to produce, we have to make
arrangements for storage and distribution to the market. We rely on local
infrastructure and the availability of transportation for storage and shipment
of our products, but infrastructure development and storage and transportation
facilities may be insufficient for our needs at commercially acceptable terms in
the localities in which we operate. This could be particularly problematic to
the extent that our operations are conducted in remote areas that are difficult
to access, such as areas that are distant from shipping and/or pipeline
facilities. In certain areas, we may be required to rely on only one gathering
system, trucking company or pipeline, and, if so, our ability to market our
production would be subject to their reliability and operations. These factors
may affect our ability to explore and develop properties and to store and
transport our oil and gas production and may increase our expenses.
Furthermore,
future instability in one or more of the countries in which we will operate,
weather conditions or natural disasters, actions by companies doing business in
those countries, labor disputes or actions taken by the international community
may impair the distribution of oil and/or natural gas and in turn diminish our
financial condition or ability to maintain our operations.
38
Maintaining
and Improving Our Financial Controls May Strain Our Resources and Divert
Management's Attention, and If We Are Not Able to Report That We Have Effective
Internal Controls Our Stock Price May Suffer.
We are
subject to the requirements of the Securities Exchange Act of 1934, or the
Exchange Act, including the requirements of the Sarbanes-Oxley Act of 2002. The
requirements of these rules and regulations have caused us to incur significant
legal and financial compliance costs, make some activities more difficult, time
consuming or costly and may also place undue strain on our personnel, systems
and resources. The Sarbanes-Oxley Act requires, among other things, that we
maintain effective disclosure controls and procedures and internal controls over
financial reporting. This can be difficult to do. As a result of this and
similar activities, management's attention may be diverted from other business
concerns, which could have a material adverse effect on our business, financial
condition and results of operations.
At year
end 2007 and during the first three quarters of 2008, we had a material weakness
in our internal control over financial reporting. Significant
resources were required to remediate this weakness. If we have one or
more additional material weaknesses in the future, there is a possibility that
this could result in a restatement of our financial statements or impact our
ability to accurately report financial information on a timely basis, which
could adversely affect our stock price. Further, the presence of one or more
material weaknesses could cause us to not be able to timely file our periodic
reports with the SEC, which could also result in law suits or diversion of
management's attention from our business.
Integration
of Gran Tierra and Solana’s Businesses, Personnel and Financial Controls May Be
More Difficult Than Expected, Which Could Strain the Combined Company’s
Operations.
In 2009,
Gran Tierra has undertaken continuing efforts to integrate its personnel,
accounting and other systems, and operations. This can be difficult to do and
will require significant management and other resources. For example, the
combined company will be subject to the requirements of the Sarbanes-Oxley Act
of 2002, to which Solana has not been subject. If there are difficulties in
integrating Solana’s systems into the Gran Tierra systems so that the combined
company cannot meet all of its requirements under the Sarbanes-Oxley Act, this
could cause a significant diversion of management’s attention from running the
business, may cause us to report one or more material weaknesses in our internal
control over financial reporting, may cause other failures to comply with the
Sarbanes-Oxley Act, or may be expensive in legal, financial or other costs to
cause our company to become compliant, any of which could be time-consuming or
costly and may also place undue strain on the personnel, systems and resources
of our company and cause the stock price of our company to decline.
Guerrilla
Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned
About Safeguarding Our Operations and Personnel in
Colombia.
A 40-year
armed conflict between government forces and anti-government insurgent groups
and illegal paramilitary groups - both funded by the drug trade - continues in
Colombia. Insurgents continue to attack civilians and violent guerilla activity
continues in many parts of the country.
We have
interests in five oil producing basins in Colombia - in the Middle Magdalena,
Lower Magdalena, Llanos, Putumayo and Catatumbo basins. The Putumayo
and Catatumbo regions have been prone to guerilla activity in the past. In 1989,
Argosy’s facilities in one field were attacked by guerillas and operations were
briefly disrupted. Pipelines have also been targets, including the Ecopetrol -
operated Trans Andean export pipeline which transports oil from the Putumayo
region. In March and April of 2008, sections of the Trans Andean pipeline
were blown up by guerillas, which temporarily reduced our deliveries to
Ecopetrol in the first quarter of 2008. Ecopetrol was able to restore deliveries
within two weeks of these attacks. In June 2009, production from Colombia
was reduced for 14 days as a result of Ecopetrol’s pipeline delivery being
disrupted in Colombia. In July and August of 2009, sections of the same pipeline
were blown up, temporarily reducing our deliveries to Ecopetrol for 31
consecutive days.
Continuing
attempts to reduce or prevent guerilla activity may not be successful and
guerilla activity may disrupt our operations in the future. There can also be no
assurance that we can maintain the safety of our operations and personnel in
Colombia or that this violence will not affect our operations in the future.
Continued or heightened security concerns in Colombia could also result in a
significant loss to us.
Our Oil Sales
Will Depend on a Relatively Small Group of Customers, Which Could Adversely
Affect Our Financial Results.
Oil sales
in Colombia are made mainly to Ecopetrol. While oil prices in Colombia are
related to international market prices, lack of competition and reliance on a
limited number of customers for sales of oil may diminish prices and depress our
financial results.
The
entire Argentine domestic refining market is small and export opportunities are
limited by available infrastructure. As a result, our oil sales in Argentina
will depend on a relatively small group of customers, and currently, on just
three customers. The lack of competition in this market could result in
unfavorable sales terms which, in turn, could adversely affect our financial
results. Currently all operators in Argentina are operating without
sales contracts. We cannot provide any certainty as to when the situation will
be resolved or what the final outcome will be.
Our Operations
Involve Substantial Costs and are Subject to Certain Risks Because the Oil and
Gas Industries in the Countries in Which We Operate are Less
Developed.
The oil
and gas industry in South America is not as efficient or developed as the oil
and gas industry in North America. As a result, our exploration and development
activities may take longer to complete and may be more expensive than similar
operations in North America. The availability of technical expertise, specific
equipment and supplies may be more limited than in North America. We expect that
such factors will subject our international operations to economic and operating
risks that may not be experienced in North American
operations.
39
Our Business is
Subject to Local Legal, Political and Economic Factors Which are Beyond Our
Control, Which Could Impair Our Ability to Expand Our Operations or Operate
Profitably.
We
operate our business in Colombia, Argentina and Peru, and expect to expand
our operations into Brazil and 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 and other laws
or policies affecting environmental issues (including land use and water use),
workplace safety, foreign investment, foreign trade, investment or taxation, as
well as restrictions imposed on the oil and natural gas industry, such as
restrictions on production, price controls and export controls. South America
has a history of political and economic instability. This instability could
result in new governments or the adoption of new policies, laws or regulations
that might assume a substantially more hostile attitude toward foreign
investment, including the imposition of additional taxes. In an extreme case,
such a change could result in termination of contract rights and expropriation
of foreign-owned assets. Any changes in oil and gas or investment regulations
and policies or a shift in political attitudes in Argentina, Colombia, Peru or
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, changes in political views
regarding the exploitation of natural resources and economic pressures may make
it more difficult for us to negotiate agreements on favorable terms, obtain
required licenses, comply with regulations or effectively adapt to adverse
economic changes, such as increased taxes, higher costs, inflationary pressure
and currency fluctuations.
Starting
on November 21, 2008, we were forced to reduce production in Colombia on a
gradual basis, culminating on December 11, 2008 when we suspended all production
from the Santana, Guayuyaco and Chaza Blocks in the Putumayo
Basin. This temporary suspension of production operations was the
result of a declaration of a state of emergency and force majeure by Ecopetrol
due to a general strike in the region. In January 2009, the situation
was resolved and we were able to resume production and sales
shipments.
Negative
Economic, Political and Regulatory Developments in Argentina, Including Export
Controls May Negatively Affect our
Operations.
The
Argentine economy has experienced volatility in recent decades. This volatility
has included periods of low or negative growth and variable levels of inflation.
Inflation was at its peak in the 1980’s and early 1990’s. In late-2001 there was
a deep fiscal crisis in Argentina involving restrictions on banking
transactions, imposition of exchange controls, suspension of payment of
Argentina’s public debt and abrogation of the one-to-one peg of the peso to the
dollar. For the next year, Argentina experienced contractions in economic
growth, increasing inflation and a volatile exchange rate. Subsequently,
Argentina experienced a period of GDP growth, normalized inflation, and
strengthened public finances. However, there is no guarantee of economic
stability. The economy faltered and the government experienced some
difficulty in 2008. Inflation has been rising and government
popularity has dropped, due to the economic situation and the unpopularity of
some of the programs the government tried to implement to deal with
it. The government applied export controls to agricultural products
which were highly unpopular and caused demonstrations and labor strikes across
the country.
The crude
oil and natural gas industry in Argentina is subject to extensive regulation
including land tenure, exploration, development, production, refining,
transportation, and marketing, imposed by legislation enacted by various levels
of government and with respect to pricing and taxation of crude oil and natural
gas by agreements among the federal and provincial governments, all of which are
subject to change and could have a material impact on our business in Argentina.
The Federal Government of Argentina has implemented controls for domestic fuel
prices and has placed a tax on crude oil and natural gas exports.
Any
future regulations that limit the amount of oil and gas that we could sell or
any regulations that limit price increases in Argentina and elsewhere could
severely limit the amount of our revenue and affect our results of
operations.
Our
agreements with Refiner S.A. expired on January 1, 2008, and renegotiation,
though currently underway, has been delayed due to the introduction of a new
withholding tax regime for crude oil and refined oil products exported and sold
domestically in Argentina. Currently all oil and gas producers in
Argentina are operating without sales contracts. The new withholding
tax regime was introduced without specific guidance as to its application.
Producers and refiners of oil in Argentina have been unable to determine an
agreed sales price for oil deliveries to refineries. Also, the price for
refiners’ gasoline production has been capped below the price that would be
received for crude oil. Therefore, the refineries’ price offered to oil
producers reflects their price received, less taxes and operating costs and
their usual mark up. Along with most other oil producers in Argentina, we
are continuing deliveries to the refinery. In our case we are
negotiating sales on a spot price basis with two refineries. Refiner
S.A. takes most of our oil and the price is negotiated on a month by month
basis. We deliver two truckloads per day to Polipetrol in Mendoza
province, and that price is negotiated weekly. The Provincial
Governments have also been hurt by these changes as their effective royalty take
has been reduced and capital investment in oilfields has declined. We are
working with other oil and gas producers in the area, as well as Refiner S.A.,
and provincial governments, to lobby the federal government for
change.
40
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;
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·
|
the
Export-Import Bank of the United States and the Overseas Private
Investment Corporation would not approve financing for new projects in
Colombia;
|
·
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United
States representatives at multilateral lending institutions would be
required to vote against all loan requests from Colombia, although such
votes would not constitute vetoes;
and
|
·
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the
President of the United States and Congress would retain the right to
apply future trade sanctions.
|
Each of
these consequences could result in adverse economic consequences in Colombia and
could further heighten the political and economic risks associated with our
operations there. Any changes in the holders of significant government offices
could have adverse consequences on our relationship with the Colombian national
oil company and the Colombian government’s ability to control guerrilla
activities and could exacerbate the factors relating to our foreign operations.
Any sanctions imposed on Colombia by the United States government could threaten
our ability to obtain necessary financing to develop the Colombian properties or
cause Colombia to retaliate against us, including by nationalizing our Colombian
assets. Accordingly, the imposition of the foregoing economic and trade
sanctions on Colombia would likely result in a substantial loss and a decrease
in the price of our common stock. The United States may impose sanctions on
Colombia in the future, and we cannot predict the effect in Colombia that these
sanctions might cause.
Maintaining
Good Community Relationships and Being a Good Corporate Citizen may be Costly
and Difficult to Manage.
Our
operations have a significant effect on the areas in which we
operate. In order to enjoy the confidence of local populations and
the local governments, we must invest in the communities where were
operate. In many cases, these communities are impoverished and
lacking in many resources taken for granted in North America. The
opportunities for investment are large, many and varied; however, we must be
careful to invest carefully in projects that will truly benefit these
areas. Improper management of these investments and relationships
could lead to a delay in operations, loss of license or major impact to our
reputation and share price.
Foreign Currency
Exchange Rate Fluctuations May Affect Our Financial
Results.
We expect
to sell our oil and natural gas production under agreements that will be
denominated in United States dollars and foreign currencies. Many of the
operational and other expenses we incur will be paid in the local currency of
the country where we perform our operations. Our production is primarily
invoiced in United States dollars, but payment is also made in Argentine and
Colombian pesos, at the then-current exchange rate. As a result, we are exposed
to translation risk when local currency financial statements are translated to
United States dollars, our company’s functional currency. Since we began
operating in Argentina (September 1, 2005), the rate of exchange between
the Argentine peso and U.S. dollar has varied between 3.05 pesos to one U.S.
dollar to 3.51 pesos to the U.S. dollar, a fluctuation of approximately 15%.
Exchange rates between the Colombian peso and U.S. dollar have varied between
2,632 pesos to one U.S. dollar to 1,648 pesos to one U.S. dollar since
September 1, 2005, a fluctuation of approximately 60%.
Exchange Controls
and New Taxes Could Materially Affect our Ability to Fund Our Operations and
Realize Profits from Our Foreign
Operations.
Foreign
operations may require funding if their cash requirements exceed operating cash
flow. To the extent that funding is required, there may be exchange controls
limiting such funding or adverse tax consequences associated with such funding.
In addition, taxes and exchange controls may affect the dividends that we
receive from foreign subsidiaries.
Exchange
controls may prevent us from transferring funds abroad. For example, the
Argentine government has imposed a number of monetary and currency exchange
control measures that include restrictions on the free disposition of funds
deposited with banks and tight restrictions on transferring funds abroad, with
certain exceptions for transfers related to foreign trade and other authorized
transactions approved by the Argentine Central Bank. The Central Bank may
require prior authorization and may or may not grant such authorization for our
Argentine subsidiaries to make dividend payments to us and there may be a tax
imposed with respect to the expatriation of the proceeds from our foreign
subsidiaries.
41
*We
Must Maintain Effective Registration Statements For All of Our Private
Placements of Our Common Stock.
We are
required to maintain registration statements periodically in accordance with the
Registration Rights Agreements for our 2005 and 2006 private placements of
units. Keeping these registration statements effective may be costly and
could divert management’s attention from running our business. Failure to
maintain these registration statements could result in the loss of ability for
some shareholders to trade their shares, and could affect the price of our
stock.
Risks
Related to Our Industry
Unless We are
Able to Replace Our Reserves, and Develop Oil and Gas Reserves on an
Economically Viable Basis, Our Reserves, Production and Cash Flows May Decline
as a Result.
Our
future success depends on our ability to find, develop and acquire additional
oil and gas reserves that are economically recoverable. Without successful
exploration, development or acquisition activities, our reserves and production
will decline. We may not be able to find, develop or acquire additional reserves
at acceptable costs.
To the
extent that we succeed in discovering oil and/or natural gas, reserves may not
be capable of production levels we project or in sufficient quantities to be
commercially viable. On a long-term basis, our company’s viability depends on
our ability to find or acquire, develop and commercially produce additional oil
and gas reserves. Without the addition of reserves through exploration,
acquisition or development activities, our reserves and production will decline
over time as reserves are produced. Our future reserves will depend not only on
our ability to develop then-existing properties, but also on our ability to
identify and acquire additional suitable producing properties or prospects, to
find markets for the oil and natural gas we develop and to effectively
distribute our production into our markets.
Future
oil and gas exploration may involve unprofitable efforts, not only from dry
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of
drilling, completion and operating costs. In addition, drilling hazards or
environmental damage could greatly increase the cost of operations, and various
field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or
consents, shut-downs of connected wells resulting from extreme weather
conditions, problems in storage and distribution and adverse geological and
mechanical conditions. While we will endeavor to effectively manage these
conditions, we may not be able to do so optimally, and we will not be able to
eliminate them completely in any case. Therefore, these conditions could
diminish our revenue and cash flow levels and result in the impairment of our
oil and natural gas interests.
We are Required
to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain
These Licenses Could Cause Significant Delays and Expenses That Could Materially
Impact Our Business.
We are
subject to licensing and permitting requirements relating to drilling for oil
and natural gas. We may not be able to obtain, sustain or renew such licenses.
Regulations and policies relating to these licenses and permits may change or be
implemented in a way that we do not currently anticipate. These licenses and
permits are subject to numerous requirements, including compliance with the
environmental regulations of the local governments. As we are not the operator
of all the joint ventures we are currently involved in, we may rely on the
operator to obtain all necessary permits and licenses. If we fail to comply with
these requirements, we could be prevented from drilling for oil and natural gas,
and we could be subject to civil or criminal liability or fines. Revocation or
suspension of our environmental and operating permits could have a material
adverse effect on our business, financial condition and results of
operations.
Our Exploration
for Oil and Natural Gas Is Risky and May Not Be Commercially Successful,
Impairing Our Ability to Generate Revenues from Our
Operations.
Oil and
natural gas exploration involves a high degree of risk. These risks are more
acute in the early stages of exploration. Our exploration expenditures may not
result in new discoveries of oil or natural gas in commercially viable
quantities. It is difficult to project the costs of implementing an exploratory
drilling program due to the inherent uncertainties of drilling in unknown
formations, the costs associated with encountering various drilling conditions,
such as over pressured zones and tools lost in the hole, and changes in drilling
plans and locations as a result of prior exploratory wells or additional seismic
data and interpretations thereof. If exploration costs exceed our estimates, or
if our exploration efforts do not produce results which meet our expectations,
our exploration efforts may not be commercially successful, which could
adversely impact our ability to generate revenues from our
operations.
42
Estimates of Oil
and Natural Gas Reserves that We Make May Be Inaccurate and Our Actual Revenues
May Be Lower and Our Operating Expenses may be Higher than Our Financial
Projections.
We will
make estimates of oil and natural gas reserves, upon which we will base our
financial projections. We will make these reserve estimates using various
assumptions, including assumptions as to oil and natural gas prices, drilling
and operating expenses, capital expenditures, taxes and availability of funds.
Some of these assumptions are inherently subjective, and the accuracy of our
reserve estimates relies in part on the ability of our management team,
engineers and other advisors to make accurate assumptions. Economic factors
beyond our control, such as interest rates and exchange rates, will also impact
the value of our reserves. The process of estimating oil and gas reserves is
complex, and will require us to use significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each property. As a result, our reserve estimates will be inherently
imprecise. Actual future production, oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable oil and gas reserves may vary substantially from those we estimate.
If actual production results vary substantially from our reserve estimates, this
could materially reduce our revenues and result in the impairment of our oil and
natural gas interests.
Exploration,
development, production, marketing (including distribution costs) and regulatory
compliance costs (including taxes) will substantially impact the net revenues we
derive from the oil and gas that we produce. These costs are subject to
fluctuations and variation in different locales in which we operate, and we may
not be able to predict or control these costs. If these costs exceed our
expectations, this may adversely affect our results of operations. In addition,
we may not be able to earn net revenue at our predicted levels, which may impact
our ability to satisfy our obligations.
If
Oil and Natural Gas Prices Decrease, We May be Required to Take Write-Downs of
the Carrying Value of Our Oil and Natural Gas Properties.
We follow
the full cost method of accounting for our oil and gas properties. A separate
cost center is maintained for expenditures applicable to each country in which
we conduct exploration and/or production activities. Under this method, the net
book value of properties on a country-by-country basis, less related deferred
income taxes, may not exceed a calculated “ceiling”. The ceiling is the
estimated after tax future net revenues from proved oil and gas properties,
discounted at 10% per year. In calculating discounted future net revenues, oil
and natural gas prices in effect at the time of the calculation are held
constant, except for changes which are fixed and determinable by existing
contracts. The net book value is compared to the ceiling on a quarterly basis.
The excess, if any, of the net book value above the ceiling is required to be
written off as an expense. Under SEC full cost accounting rules, any write-off
recorded may not be reversed even if higher oil and natural gas prices increase
the ceiling applicable to future periods. Future price decreases could result in
reductions in the carrying value of such assets and an equivalent charge to
earnings.
Drilling New
Wells Could Result in New Liabilities, Which Could Endanger Our Interests in Our
Properties and Assets.
There are
risks associated with the drilling of oil and natural gas wells, including
encountering unexpected formations or pressures, premature declines of
reservoirs, blow-outs, craterings, sour gas releases, fires and
spills. For example, on February 7, 2009 we experienced an incident
at our Juanambu 1 well, involving a fire in a generator, resulting in total
damage to equipment estimated at $500,000, and production in the amount of
approximately $125,000 being deferred due to shutting down production facilities
while dealing with the incident. The occurrence of any of these events could
significantly reduce our revenues or cause substantial losses, impairing our
future operating results. We may become subject to liability for pollution,
blow-outs or other hazards. Incidents such as these can lead to serious injury,
property damage and even loss of life. We will obtain insurance with
respect to these hazards, but such insurance has limitations on liability that
may not be sufficient to cover the full extent of such liabilities. The payment
of such liabilities could reduce the funds available to us or could, in an
extreme case, result in a total loss of our properties and assets. Moreover, we
may not be able to maintain adequate insurance in the future at rates that are
considered reasonable. Oil and natural gas production operations are also
subject to all the risks typically associated with such operations, including
premature decline of reservoirs and the invasion of water into producing
formations.
Our Inability to
Obtain Necessary Facilities and/or Equipment Could Hamper Our
Operations.
Oil and
natural gas exploration and development activities are dependent on the
availability of drilling and related equipment, transportation, power and
technical support in the particular areas where these activities will be
conducted, and our access to these facilities may be limited. To the extent that
we conduct our activities in remote areas, needed facilities or equipment may
not be proximate to our operations, which will increase our expenses. Demand for
such limited equipment and other facilities or access restrictions may affect
the availability of such equipment to us and may delay exploration and
development activities. The quality and reliability of necessary facilities or
equipment may also be unpredictable and we may be required to make efforts to
standardize our facilities, which may entail unanticipated costs and delays.
Shortages and/or the unavailability of necessary equipment or other facilities
will impair our activities, either by delaying our activities, increasing our
costs or otherwise.
Decommissioning
Costs Are Unknown and May be Substantial; Unplanned Costs Could Divert Resources
from Other Projects.
We may
become responsible for costs associated with abandoning and reclaiming wells,
facilities and pipelines which we use for production of oil and gas reserves.
Abandonment and reclamation of these facilities and the costs associated
therewith is often referred to as “decommissioning.” We have determined that we
require a reserve account for these potential costs in respect of our current
properties and facilities at this time, and have booked such reserve on our
financial statements. If decommissioning is required before economic depletion
of our properties or if our estimates of the costs of decommissioning exceed the
value of the reserves remaining at any particular time to cover such
decommissioning costs, we may have to draw on funds from other sources to
satisfy such costs. The use of other funds to satisfy decommissioning costs
could impair our ability to focus capital investment in other areas of our
business.
43
Drilling Oil and
Gas Wells and Production and Transportation Activity Could be Hindered by
Earthquakes and Weather-Related Operating Risks.
We are
subject to operating hazards normally associated with the exploration and
production of oil and gas, including blowouts, explosions, oil spills,
cratering, pollution, earthquakes, hurricanes, and fires. The occurrence of any
such operating hazards could result in substantial losses to us due to injury or
loss of life and damage to or destruction of oil and gas wells, formations,
production facilities or other properties.
The
majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol
and sales of oil could be disrupted by damage to this pipeline. Once delivered
to Ecopetrol, all of our current oil production in Colombia is transported by an
export pipeline which provides the only access to markets for our oil. Without
other transportation alternatives, sales of oil could be disrupted by landslides
or other natural events which impact this pipeline.
As the
majority of current oil production in Argentina is trucked to a local refinery,
sales of oil can be delayed by adverse weather and road conditions, particularly
during the months November through February when the area is subject to periods
of heavy rain and flooding. While storage facilities are designed to accommodate
ordinary disruptions without curtailing production, delayed sales will delay
revenues and may adversely impact our working capital position in Argentina.
Furthermore, a prolonged disruption in oil deliveries could exceed storage
capacities and shut-in production, which could have a negative impact on future
production capability.
Prices and
Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate
Significantly, Which Could Reduce Profitability, Growth and the Value of Gran
Tierra.
Oil and
natural gas are commodities whose prices are determined based on world demand,
supply and other factors, all of which are beyond our control. World prices for
oil and natural gas have fluctuated widely in recent years. The average price
for WTI in 2000 was $30 per barrel. In 2006, it was $66 per barrel, in 2007 it
was $72 per barrel and in 2008 it was $100 per barrel. However, the average
price for the nine months ended September 30, 2009 was $56.99, 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 2008 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.
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.
44
Our Insurance May
Be Inadequate to Cover Liabilities We May Incur.
Our
involvement in the exploration for and development of oil and natural gas
properties may result in our becoming subject to liability for pollution,
blow-outs, property damage, personal injury or other hazards. Although we have
insurance in accordance with industry standards to address such risks, such
insurance has limitations on liability that may not be sufficient to cover the
full extent of such liabilities. In addition, such risks may not, in all
circumstances be insurable or, in certain circumstances, we may choose not to
obtain insurance to protect against specific risks due to the high premiums
associated with such insurance or for other reasons. The payment of such
uninsured liabilities would reduce the funds available to us. If we suffer a
significant event or occurrence that is not fully insured, or if the insurer of
such event is not solvent, we could be required to divert funds from capital
investment or other uses towards covering our liability for such
events.
Policies,
Procedures and Systems to Safeguard Employee Health, Safety and Security May Not
be Adequate.
Oil and
natural gas exploration and production is dangerous. Detailed and
specialized policies, procedures and systems are required to safeguard employee
health, safety and security. We have undertaken to implement best
practices for employee health, safety and security; however, if these policies,
procedures and systems are not adequate, or employees do not receive adequate
training, the consequences can be severe including serious injury or loss of
life, which could impair our operations and cause us to incur significant legal
liability.
Challenges to Our
Properties May Impact Our Financial Condition.
Title to
oil and natural gas interests is often not capable of conclusive determination
without incurring substantial expense. While we intend to make appropriate
inquiries into the title of properties and other development rights we acquire,
title defects may exist. In addition, we may be unable to obtain adequate
insurance for title defects, on a commercially reasonable basis or at all. If
title defects do exist, it is possible that we may lose all or a portion of our
right, title and interest in and to the properties to which the title defects
relate.
Furthermore,
applicable governments may revoke or unfavorably alter the conditions of
exploration and development authorizations that we procure, or third parties may
challenge any exploration and development authorizations we procure. Such rights
or additional rights we apply for may not be granted or renewed on terms
satisfactory to us.
If our
property rights are reduced, whether by governmental action or third party
challenges, our ability to conduct our exploration, development and production
may be impaired.
We Will Rely on
Technology to Conduct Our Business and Our Technology Could Become Ineffective
Or Obsolete.
We rely
on technology, including geographic and seismic analysis techniques and economic
models, to develop our reserve estimates and to guide our exploration and
development and production activities. We will be required to continually
enhance and update our technology to maintain its efficacy and to avoid
obsolescence. The costs of doing so may be substantial, and may be higher than
the costs that we anticipate for technology maintenance and development. If we
are unable to maintain the efficacy of our technology, our ability to manage our
business and to compete may be impaired. Further, even if we are able to
maintain technical effectiveness, our technology may not be the most efficient
means of reaching our objectives, in which case we may incur higher operating
costs than we would were our technology more efficient.
Risks Related to Our Common
Stock
The Market Price
of Our Common Stock May Be Highly Volatile and Subject to Wide
Fluctuations.
The
market price of our common stock may be highly volatile and could be subject to
wide fluctuations in response to a number of factors that are beyond our
control, including:
·
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dilution
caused by our issuance of additional shares of common stock and other
forms of equity securities, which we expect to make in connection with
future capital financings to fund our operations and growth, to attract
and retain valuable personnel and in connection with future strategic
partnerships with other companies;
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·
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announcements
of new acquisitions, reserve discoveries or other business initiatives by
our competitors;
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·
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fluctuations
in revenue from our oil and natural gas
business;
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·
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changes
in the market and/or WTI price for oil and natural gas commodities and/or
in the capital markets generally;
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45
·
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changes
in the demand for oil and natural gas, including changes resulting from
the introduction or expansion of alternative fuels;
and
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·
|
changes
in the social, political and/or legal climate in the regions in which we
will operate.
|
In
addition, the market price of our common stock could be subject to wide
fluctuations in response to:
·
|
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
fourteen separate dates beginning on July 16, 2009 and ending on September 30,
2009, we sold an aggregate of 604,283 shares of our common stock for an
aggregate purchase price of $673,020. These shares were issued to nineteen
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 September 9,
2009, we issued 104,761 shares of our common stock to a holder of
exchangeable shares, which were issued by a subsidiary of Gran Tierra in a share
exchange on November 10, 2005. The shares were issued to this holder in reliance
on Regulation S promulgated by the SEC as the investor was not a resident of the
United States.
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY
HOLDERS
None.
46
ITEM 5. OTHER
INFORMATION
None.
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.
Company Name | |||
Date:
November 5, 2009
|
By:
|
/s/ Dana Coffield | |
By: Dana Coffield | |||
Its: Chief Executive Officer | |||
Company Name | |||
Date:
November 5, 2009
|
By:
|
/s/ Martin Eden | |
By: Martin Eden | |||
Its: Chief Financial Officer | |||
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, 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.
|
Filed
herewith.
|
||
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.
|
47
10.1 Assignment
and Assumption Agreement, dated as of August 24, 2009, by and among Gran Tierra
Energy Inc., Gran Tierra Energy Cayman Islands Inc., and Standard Bank
PLC.
10.2 Amended
and Restated Credit Agreement, dated as of August 24, 2009, by and among Gran
Tierra Energy Inc., Gran Tierra Energy Colombia, Ltd., Argosy Energy, LLC,
Solana Petroleum Exploration (Colombia) Limited, Solana Resources Limited, and
Standard Bank PLC.
10.3 First
Priority Open Pledge Agreement over Credit Rights Derived from Hydrocarbon
Commercial Sales Agreements, dated as of August 24, 2009, by and between Solana
Petroleum Exploration (Colombia) Limited and Standard Bank PLC.
10.4 First
Priority Open Pledge Agreement over a Commercial Establishment, dated as of
August 24, 2009, by and between Solana Petroleum Exploration (Colombia) Limited
and Standard Bank PLC.
10.5 Amended
and Restated First Priority Open Pledge Agreement over Credit Rights Derived
from Crude Oil Commercial Sales Agreements, dated as of August 24, 2009, by and
between Gran Tierra Energy Colombia, Ltd., and Standard Bank PLC.
10.6 Cancellation
of BNP Pledge over Credit Rights, dated as of August 20, 2009, by BNP
Paribas.
10.7 Cancellation
of BNP Pledge over Commercial Establishment, dated as of August 21, 2009, by BNP
Paribas.
10.8 Collection
Account Pledge Agreement, dated as of August 24, 2009, by and between Solana
Petroleum Exploration (Colombia) Limited and Standard Bank PLC.
10.9 Deposit
Account Control Agreement, dated as of August 24, 2009, by and among Solana
Petroleum Exploration (Colombia) Limited, BNP Paribas, and Standard Bank
PLC.
10.10 Letter
regarding Pledge Agreements, dated as of August 24, 2009, by and among the Gran
Tierra Energy Cayman Islands Inc, Gran Tierra Energy Colombia, Ltd., Argosy
Energy, LLC, GTE Colombia Holdings LLC, and Standard Bank PLC.
10.11 Release
of Share Pledge Agreement, dated as of August 24, 2009, by and between Gran
Tierra Energy Inc. and Standard Bank PLC.
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.
|
48