Gran Tierra Energy 10Q 2009 Q3 Quarterly report

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

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

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)

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)

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)

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)

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.

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.

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.

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

	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.

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).

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.

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

	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

	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.

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.

As at September 30, 2009

Fair Value Measurements Using:

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Carrying

Total Fair

Markets

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

Amount

Value

(Level 1)

(Level 2)

(Level 3)

Financial Assets

(Thousands of U.S. Dollars)

Crude oil collar

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.

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.

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.

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.

·	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.

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.

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.

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	)

(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.

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.

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.

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.

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	)

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

The United States Government May Impose Economic or Trade Sanctions on Colombia That Could Result In A Significant Loss To Us.

Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counternarcotics agreements may result in any of the following:

·	all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended;

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

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

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

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with 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.

*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.

Estimates of Oil and Natural Gas Reserves that We Make May Be Inaccurate and Our Actual Revenues May Be Lower and Our Operating Expenses may be Higher than Our Financial Projections.

We will make estimates of oil and natural gas reserves, upon which we will base our financial projections. We will make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as interest rates and exchange rates, will also impact the value of our reserves. The process of estimating oil and gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

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

If Oil and Natural Gas Prices Decrease, We May be Required to Take Write-Downs of the Carrying Value of Our Oil and Natural Gas Properties.

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices in effect at the time of the calculation are held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.

Drilling New Wells Could Result in New Liabilities, Which Could Endanger Our Interests in Our Properties and Assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. For example, on February 7, 2009 we experienced an incident at our Juanambu 1 well, involving a fire in a generator, resulting in total damage to equipment estimated at $500,000, and production in the amount of approximately $125,000 being deferred due to shutting down production facilities while dealing with the incident. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. Incidents such as these can lead to serious injury, property damage and even loss of life. We will obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Our Inability to Obtain Necessary Facilities and/or Equipment Could Hamper Our Operations.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities or equipment may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities or equipment may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

Decommissioning Costs Are Unknown and May be Substantial; Unplanned Costs Could Divert Resources from Other Projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have determined that we require a reserve account for these potential costs in respect of our current properties and facilities at this time, and have booked such reserve on our financial statements. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Drilling Oil and Gas Wells and Production and Transportation Activity Could be Hindered by Earthquakes and Weather-Related Operating Risks.

We are subject to operating hazards normally associated with the exploration and production of oil and gas, including blowouts, explosions, oil spills, cratering, pollution, earthquakes, hurricanes, and fires. The occurrence of any such operating hazards could result in substantial losses to us due to injury or loss of life and damage to or destruction of oil and gas wells, formations, production facilities or other properties.

The majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol and sales of oil could be disrupted by damage to this pipeline. Once delivered to Ecopetrol, all of our current oil production in Colombia is transported by an export pipeline which provides the only access to markets for our oil. Without other transportation alternatives, sales of oil could be disrupted by landslides or other natural events which impact this pipeline.

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

Prices and Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate Significantly, Which Could Reduce Profitability, Growth and the Value of Gran Tierra.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for WTI in 2000 was $30 per barrel. In 2006, it was $66 per barrel, in 2007 it was $72 per barrel and in 2008 it was $100 per barrel. However, the average price for 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.

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:

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;

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

·	fluctuations in revenue from our oil and natural gas business;

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

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

·	changes in the social, political and/or legal climate in the regions in which we will operate.

In addition, the market price of our common stock could be subject to wide fluctuations in response to:

·	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.

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.

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.

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Litigous
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Gran Tierra Energy (GTE) 10-Q2009 Q3 Quarterly report

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