Edgar Filing: GRAN TIERRA ENERGY, INC.

Unassociated Document

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, 2010


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		FOR THE TRANSITION PERIOD FROM __________ TO __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

Nevada		98-0479924
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)

300, 625 11th Avenue S.W. Calgary, Alberta, Canada		T2R 0E1
(Address of principal executive offices)		(Zip code)

(403) 265-3221

(Registrant’s telephone number,

including area code)

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 x 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 o
Non-Accelerated Filer o	(do not check if a smaller reporting company) Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO x

On November 2, 2010, the following numbers of shares of the registrant’s capital stock were outstanding: 238,591,271 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 7,811,112 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 10,657,065 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	16

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32

ITEM 4.	CONTROLS AND PROCEDURES	32

	PART II - OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	33

ITEM 1A.	RISK FACTORS	33

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	43

ITEM 6.	EXHIBITS	43

SIGNATURES		43

EXHIBIT INDEX		44

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,
	2010			2009			2010			2009

REVENUE AND OTHER INCOME
Oil and natural gas sales	$	84,110		$	75,171		$	260,759		$	166,606
Interest		459			183			1,034			824
		84,569			75,354			261,793			167,430
EXPENSES
Operating		19,401			9,099			39,028			25,063
Depletion, depreciation, accretion, and impairment		35,254			35,246			107,238			95,466
General and administrative		10,977			7,076			27,848			19,226
Derivative financial instruments (gain) loss (Note 10)		-			(77	)		(44	)		207
Foreign exchange loss		16,320			18,867			33,740			32,353
		81,952			70,211			207,810			172,315

INCOME (LOSS) BEFORE INCOME TAXES		2,617			5,143			53,983			(4,885	)
Income tax expense (Note 7)		(5,894	)		(7,959	)		(29,929	)		(11,999	)
NET (LOSS) INCOME AND COMPREHENSIVE (LOSS) INCOME		(3,277	)		(2,816	)		24,054			(16,884	)
RETAINED EARNINGS (ACCUMULATED DEFICIT), BEGINNING OF PERIOD		48,256			(7,084	)		20,925			6,984
RETAINED EARNINGS (ACCUMULATED DEFICIT), END OF PERIOD	$	44,979		$	(9,900	)	$	44,979		$	(9,900	)

NET (LOSS) INCOME PER SHARE — BASIC	$	(0.01	)	$	(0.01	)	$	0.10		$	(0.07	)
NET (LOSS) INCOME PER SHARE — DILUTED	$	(0.01	)	$	(0.01	)	$	0.09		$	(0.07	)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)		254,951,642			242,232,717			252,487,462			240,585,878
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)		254,951,642			242,232,717			260,294,503			240,585,878

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

	September 30,		December 31,
	2010		2009

ASSETS
Current Assets
Cash and cash equivalents	$	308,396	$	270,786
Restricted cash		290		1,630
Accounts receivable		73,089		35,639
Inventory (Note 2)		5,479		4,879
Taxes receivable		2,310		1,751
Prepaids		1,810		1,820
Deferred tax assets (Note 7)		2,683		4,252

Total Current Assets		394,057		320,757

Oil and Gas Properties (using the full cost method of accounting)
Proved		431,952		474,679
Unproved		270,479		234,889

Total Oil and Gas Properties		702,431		709,568

Other capital assets		5,135		3,175

Total Property, Plant and Equipment (Note 4)		707,566		712,743

Other Long Term Assets
Restricted cash		846		162
Deferred tax assets (Note 7)		7,493		7,218
Other long term assets		319		347
Goodwill		102,581		102,581

Total Other Long Term Assets		111,239		110,308

Total Assets	$	1,212,862	$	1,143,808

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable (Note 8)	$	37,682	$	36,786
Accrued liabilities (Note 8)		47,560		40,229
Derivative financial instruments (Note 10)		-		44
Taxes payable		38,541		28,087
Asset retirement obligation (Note 6)		36		450

Total Current Liabilities		123,819		105,596

Long Term Liabilities
Deferred tax liabilities (Note 7)		213,451		216,625
Deferred remittance tax		1,453		903
Asset retirement obligation (Note 6)		5,025		4,258

Total Long Term Liabilities		219,929		221,786

Commitments and Contingencies (Note 9)
Shareholders’ Equity
Common shares (Note 5)		4,128		1,431
(238,161,748 and 219,459,361 common shares and 18,699,854 and 24,639,513 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2010 and December 31, 2009 respectively)
Additional paid in capital		817,505		766,963
Warrants		2,502		27,107
Retained earnings		44,979		20,925

Total Shareholders’ Equity		869,114		816,426

Total Liabilities and Shareholders’ Equity	$	1,212,862	$	1,143,808

(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,
	2010			2009

Operating Activities
Net income (loss)	$	24,054		$	(16,884	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, accretion, and impairment		107,238			95,466
Deferred taxes (Note 7)		(28,026	)		(5,650	)
Stock based compensation (Note 5)		5,424			3,483
Unrealized (gain) loss on financial instruments (Note 10)		(44	)		294
Unrealized foreign exchange loss		27,136			32,982
Settlement of asset retirement obligations (Note 6)		(263	)		(52	)
Net changes in non-cash working capital
Accounts receivable		(35,195	)		(68,633	)
Inventory		1			(286	)
Prepaids		10			102
Accounts payable and accrued liabilities		(8,402	)		6,501
Taxes receivable and payable		9,455			(12,296	)

Net cash provided by operating activities		101,388			35,027

Investing Activities
Restricted cash		656			(1,892	)
Additions to property, plant and equipment		(88,954	)		(65,595	)
Proceeds from disposition of oil and gas property		1,600			4,800
Long term assets and liabilities		28			248

Net cash used in investing activities		(86,670	)		(62,439	)

Financing Activities
Proceeds from issuance of common shares		22,892			2,257

Net cash provided by financing activities		22,892			2,257

Net increase (decrease) in cash and cash equivalents		37,610			(25,155	)
Cash and cash equivalents, beginning of period		270,786			176,754

Cash and cash equivalents, end of period	$	308,396		$	151,599

Cash	$	223,320		$	66,980
Term deposits		85,076			84,619
Cash and cash equivalents, end of period	$	308,396		$	151,599

Supplemental cash flow disclosures:
Cash paid for taxes	$	42,024		$	27,896
Non-cash investing activities:
Non-cash working capital related to property, plant and equipment	$	30,747		$	8,233

(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, 2010			December 31, 2009

Share Capital
Balance, beginning of period	$	1,431		$	226
Issue of common shares		2,697			1,205

Balance, end of period		4,128			1,431

Additional Paid in Capital
Balance, beginning of period		766,963			754,832
Issue of common shares		18,354			2,650
Exercise of warrants (Note 5)		24,605			2,777
Exercise of stock options (Note 5)		1,841			1,080
Stock based compensation expense (Note 5)		5,742			5,624

Balance, end of period		817,505			766,963

Warrants
Balance, beginning of period		27,107			29,884
Exercise of warrants (Note 5)		(24,605	)		(2,777	)

Balance, end of period		2,502			27,107

Retained Earnings
Balance, beginning of period		20,925			6,984
Net income		24,054			13,941

Balance, end of period		44,979			20,925

Total Shareholders’ Equity	$	869,114		$	816,426

(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 the 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 unaudited interim 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 unaudited 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, 2010, the results of its operations for the three and nine month periods ended September 30, 2010 and 2009, and its cash flows for the nine month periods ended September 30, 2010 and 2009.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim consolidated financial statements. Accordingly, these unaudited interim consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2009 included in the Company’s 2009 audited Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 26, 2010. The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2009 Annual Report on Form 10-K and are the same policies followed in these unaudited interim consolidated financial statements, except as disclosed below. The Company has evaluated all subsequent events through to the date these unaudited interim consolidated financial statements were issued.

Inventory

Crude oil inventories at September 30, 2010 and December 31, 2009 are $4.2 million and $3.8 million, respectively. Supplies at September 30, 2010 and December 31, 2009 are $1.3 million and $1.1 million, respectively.

New Accounting Pronouncements

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board (the “FASB”) issued revised accounting standards to improve financial reporting by enterprises involved with variable interest entities. The standards replace the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entity; or, (2) the right to receive benefits from the entity. This standard was effective for interim and annual reporting periods beginning after November 15, 2009. The implementation of this standard did not materially impact the Company’s consolidated financial position, operating results or cash flows.

Fair Value Measurements

In January 2010, the FASB issued Accounting Standards Update (“ASU”), “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”. This ASU amends existing disclosure requirements about fair value measurements by adding required disclosures about items transferred into and out of levels 1 and 2 in the fair value hierarchy; adding separate disclosures about purchases, sales, issuances, and settlements relative to level 3 measurements; and clarifying, among other things, the existing fair value disclosures about the level of disaggregation. This is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The implementation of this update on January 1, 2010 did not materially impact the Company’s disclosures.

Subsequent Events

In February 2010, the FASB issued ASU, "Subsequent Events (Topic 855)." The amendments remove the requirements for an SEC filer to disclose a date, in both issued and revised financial statements, through which subsequent events have been reviewed. This ASU was effective upon issuance. The implementation of this update did not materially impact the Company’s consolidated financial position, operating results or cash flows.

Stock Compensation

In April 2010, the FASB issued ASU, "Compensation–Stock Compensation (Topic 718)." The amendments clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, operating results or cash flows.

Receivables

In July 2010, the FASB issued ASU, "Receivables (Topic 310)." The update is intended to provide financial statement users with greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. The disclosures as of the end of a reporting period are effective for interim and annual reporting periods ending on or after December 15, 2010. The implementation of this update is not expected to materially impact the Company’s disclosures.

3. Segment and Geographic Reporting

The Company’s reportable operating segments are Colombia and Argentina based on a geographic organization. The Company is primarily engaged in the exploration and production of oil and natural gas. Peru and Brazil are not reportable segments because the level of activity is not significant at this time and are included as part of the Corporate segment. The accounting policies of the reportable operating segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and natural gas operations before income taxes.

The following tables present information on the Company’s reportable geographic segments:

	Three Months Ended September 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts (1))	Colombia		Argentina			Corporate			Total
Revenues	$	80,731	$	3,379		$	-		$	84,110
Interest income		301		-			158			459
Depletion, depreciation, and accretion (“DD&A”)		33,916		1,208			130			35,254
Depletion, depreciation, and accretion - per unit of production		28.78		18.08			-			28.31
Segment income (loss) before income taxes		8,305		(405	)		(5,283	)		2,617
Segment capital expenditures	$	22,084	$	12,289		$	13,313		$	47,686

	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
Depletion, depreciation, and accretion		33,630		1,538		78			35,246
Depletion, depreciation, and 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 (2)	$	17,024	$	1,890	$	210		$	19,124

	Nine Months Ended September 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Corporate			Total
Revenues	$	250,767	$	9,992		$	-		$	260,759
Interest income		520		19			495			1,034
Depletion, depreciation, and accretion		99,243		3,999			296			103,538
Impairment of carrying value of oil and natural gas properties		-		3,700			-			3,700
Depletion, depreciation, and accretion - per unit of production		27.57		19.20			-			27.19
Impairment of carrying value of oil and natural gas properties - per unit of production		-		17.76			-			0.97
Segment income (loss) before income taxes		74,154		(6,158	)		(14,013	)		53,983
Segment capital expenditures	$	68,531	$	16,763		$	16,752		$	102,046

	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
Depletion, depreciation, and accretion		90,565		4,671			230			95,466
Depletion, depreciation, and accretion - per unit of production		29.94		18.21			-			29.09
Segment income (loss) before income taxes		5,370		(577	)		(9,678	)		(4,885	)
Segment capital expenditures (2)	$	58,431	$	3,162		$	1,799		$	63,392

	As at September 30, 2010
(Thousands of U.S. Dollars)	Colombia		Argentina		Corporate		Total
Property, plant and equipment	$	651,390	$	33,341	$	22,835	$	707,566
Goodwill		102,581		-		-		102,581
Other assets		147,874		16,349		238,492		402,715
Total Assets	$	901,845	$	49,690	$	261,327	$	1,212,862

	As at December 31, 2009
(Thousands of U.S. Dollars)	Colombia		Argentina		Corporate		Total
Property, plant and equipment	$	681,854	$	24,510	$	6,379	$	712,743
Goodwill		102,581		-		-		102,581
Other assets		123,380		12,574		192,530		328,484
Total Assets	$	907,815	$	37,084	$	198,909	$	1,143,808

(1) Unit of production is barrel of oil equivalent with gas volumes converted at the rate of six thousand cubic feet of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices.

(2) Net of net proceeds from the disposition of the Guachiria Blocks in Colombia (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 2010, the Company has one significant customer for its Colombian crude oil, Ecopetrol S.A. (“Ecopetrol”), a Colombian government agency. Sales to Ecopetrol accounted for 96% and 95% of the Company’s revenues in the third quarter of 2010 and 2009, respectively. Sales to Ecopetrol accounted for 96% and 94% of the Company’s revenues for the nine month periods ended September 30, 2010 and 2009, respectively. In Argentina, the Company has one significant customer, Refineria del Norte S.A (“Refiner”). Sales to Refiner accounted for 4% and 5% of the Company’s revenues in the third quarter of 2010 and 2009, respectively. Sales to Refiner accounted for 4% and 6% of the Company’s revenues for the nine month periods ended September 30, 2010 and 2009, respectively.

4. Property, Plant and Equipment

	As at September 30, 2010							As at December 31, 2009
(Thousands of U.S. Dollars)	Cost		Accumulated DD&A			Net book value		Cost		Accumulated DD&A			Net book value
Oil and natural gas properties
Proved	$	711,825	$	(279,873	)	$	431,952	$	648,061	$	(173,382	)	$	474,679
Unproved		270,479		-			270,479		234,889		-			234,889
		982,304		(279,873	)		702,431		882,950		(173,382	)		709,568
Furniture and fixtures and leasehold improvements		4,940		(2,775	)		2,165		3,843		(2,185	)		1,658
Computer equipment		4,823		(2,192	)		2,631		3,148		(1,907	)		1,241
Automobiles		780		(441	)		339		513		(237	)		276
Total Property, Plant and Equipment	$	992,847	$	(285,281	)	$	707,566	$	890,454	$	(177,711	)	$	712,743

Depreciation, depletion, accretion and impairment for the nine months ended September 30, 2010 included a $3.7 million first quarter ceiling test impairment loss in the Company’s Argentina cost center.

During the nine months ended September 30, 2010, the Company capitalized $2.9 million (year ended December 31, 2009 - $1.6 million) of general and administrative expenses related to the Colombian full cost center, including $0.2 million (year ended December 31, 2009 - $0.2 million) of stock based compensation expense, and $0.9 million (year ended December 31, 2009 - $0.6 million) of general and administrative expenses in the Argentina full cost center, including $0.1 million (year ended December 31, 2009 - $0.1 million) of stock based compensation.

The unproved oil and natural gas properties at September 30, 2010 consist of exploration lands held in Colombia, Argentina, Peru, and Brazil. As at September 30, 2010, the Company had $235.8 million (December 31, 2009 - $229.1 million) in unproved assets in Colombia, $14.3 million (December 31, 2009 - $0.4 million) of unproved assets in Argentina, $14.4 million (December 31, 2009 - $5.4 million) of unproved assets in Peru, and $6.0 million (December 31, 2009 - nil) of unproved assets in Brazil. These properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.

In April 2009, Gran Tierra closed the sale of the Company’s interests in the Guachiria Norte, Guachiria, and Guachiria Sur blocks in Colombia. Principal terms included consideration of $7.0 million comprising an initial cash payment of $4.0 million at closing, followed by 15 monthly installments of $200,000 each which began on June 1, 2009 and extended through August 3, 2010. The Company recorded net proceeds of $6.3 million.

5. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share, and two shares are designated as special voting stock, par value $0.001 per share. As at September 30, 2010, outstanding share capital consists of 238,161,748 common voting shares of the Company, 10,730,012 exchangeable shares of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013, and 7,969,842 exchangeable shares of Goldstrike Exchange Co., automatically exchangeable on November 10, 2012. The exchangeable shares of Gran Tierra Exchange Co, were issued upon acquisition of Solana Resources Limited (“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, 2010, the Company had 410,750 warrants outstanding to purchase 205,375 common shares for $1.25 per share, expiring between October 1, 2010 and February 2, 2011, and 8,737,222 warrants outstanding to purchase 4,368,611 common shares for $1.05 per share, expiring between June 20, 2012 and June 30, 2012. For the nine months ended September 30, 2010, 10,438,473 common shares were issued upon the exercise of 13,731,008 warrants (nine months ended September 30, 2009, 3,224,216 common shares were issued upon the exercise of 8,919,706 warrants). Included in warrants exercised in the nine months ended September 30, 2010 were 7,145,938 warrants to purchase 7,145,938 common shares for $14.4 million, assumed in the acquisition of Solana in November 2008.

Stock Options

As at September 30, 2010, the Company has a 2007 Equity Incentive Plan, formed through the approval by shareholders of the amendment and restatement of the 2005 Equity Incentive Plan, under which the Company’s board of directors is authorized to issue options or other rights to acquire shares of the Company’s common stock. On November 14, 2008, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the number of shares of common stock available for issuance thereunder from 9,000,000 shares to 18,000,000 shares. On June 16, 2010, another amendment to the Company’s 2007 Equity Incentive plan was approved by shareholders, which increased the number of shares of common stock available for issuance thereunder from 18,000,000 shares to 23,306,100 shares.

The Company grants options to purchase common shares to certain directors, officers, employees and consultants. Each option permits the holder to purchase one common share at the stated exercise price. The options vest over three years and have a term of ten years, or three months after the grantee’s end of service to the Company, whichever occurs first. At the time of grant, the exercise price equals the market price. For the nine months ended September 30, 2010, 2,324,256 common shares were issued upon the exercise of 2,324,256 stock options (nine months ended September 30, 2009 – 602,570). The following options are outstanding as of September 30, 2010:

	Number of			Weighted Average
	Outstanding			Exercise Price
	Options			$/Option
Balance, December 31, 2009		11,088,616		$	2.43
Granted in 2010		2,940,000			5.91
Exercised in 2010		(2,324,256	)		(1.95	)
Forfeited in 2010		(261,671	)		(3.90	)
Balance, September 30, 2010		11,442,689		$	3.38

The weighted average grant date fair value for options granted in 2010 was $3.33. The intrinsic value of options exercised for the nine months ended September 30, 2010 was $9.5 million (nine months ended September 30, 2009 - $22.6 million).

The table below summarizes stock options outstanding at September 30, 2010:

	Number of		Weighted Average		Weighted
	Outstanding		Exercise Price		Average
Range of Exercise Prices ($/option)	Options		$/Option		Expiry Years
0.50 to 1.30		1,389,170	$	1.10		5.8
1.31 to 2.00		243,335		1.72		7.1
2.01 to 3.50		5,983,517		2.45		8.0
3.51 to 5.50		501,667		4.50		9.0
5.51 to 7.75		3,325,000		5.97		9.4
Total		11,442,689	$	3.38		8.2

The aggregate intrinsic value of options outstanding at September 30, 2010 is $56.1 million based on the Company’s closing stock price of $7.72 for that date. At September 30, 2010, there was $7.7 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, 2010, the stock based compensation expense was $5.7 million (nine months ended September 30, 2009 - $4.1 million) of which $4.6 million (nine months ended September 30, 2009 - $3.3 million) was recorded in general and administrative expense and $0.8 million was recorded in operating expense in the consolidated statement of operations (nine months ended September 30, 2009 – $0.2 million). For the nine months ended September 30, 2010, $0.3 million of stock based compensation was capitalized as part of exploration and development costs (nine months ended September 30, 2009 – $0.6 million).

The fair value of each stock option award is estimated on the date of grant using a 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,
	2010			2009			2010			2009
Dividend yield (per share)	$ nil			$ nil			$ nil			$ nil
Volatility		85	%		97	%		90	%		97	%
Risk-free interest rate		0.3	%		0.5	%		0.4	%		0.5	%
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,
	2010		2009		2010		2009
Weighted average number of common and exchangeable shares outstanding		254,951,642		242,232,717		252,487,462		240,585,878
Shares issuable pursuant to warrants		-		-		3,877,754		-
Shares issuable pursuant to stock options		-		-		3,929,287		-
Weighted average number of diluted common and exchangeable shares outstanding		254,951,642		242,232,717		260,294,503		240,585,878

Net Income (Loss) Per Share

For the three months ended September 30, 2010, options to purchase 11,442,689 common shares and 9,147,972 warrants to purchase 4,573,986 common shares were excluded from the diluted loss per share calculation as the instruments were anti-dilutive. For the nine months ended September 30, 2010, options to purchase 3,435,000 common shares were excluded from the diluted income per share calculation as the instruments were anti-dilutive. 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.

6. Asset Retirement Obligation

As at September 30, 2010 the Company’s asset retirement obligation was comprised of a Colombian obligation in the amount of $4.2 million (December 31, 2009 - $3.5 million) and an Argentine obligation in the amount of $0.9 million (December 31, 2009 - $1.2 million). As at September 30, 2010, the undiscounted asset retirement obligation was $12.6 million (December 31, 2009 - $7.7 million). Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties were as follows:

	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2010			December 31, 2009
Balance, beginning of period	$	4,708		$	4,251
Settlements		(263	)		(52	)
Disposal		-			(734	)
Liability incurred		307			921
Foreign exchange		38			24
Accretion		271			298
Balance, end of period	$	5,061		$	4,708

Asset retirement obligation - current	$	36		$	450
Asset retirement obligation - long term		5,025			4,258
Balance, end of period	$	5,061		$	4,708

7. Income Taxes

The income tax expense (recovery) reported differ from the amount computed by applying the US statutory rate to income before income taxes for the following reasons:

	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2010			2009 (1)
Income (loss) before income taxes	$	53,983		$	(4,885	)
		35	%		35	%
Income tax expense (recovery) expected		18,894			(1,710	)
Permanent differences		4,721			1,561
Foreign currency translation adjustments		12,060			8,015
Impact of foreign taxes		(108	)		(778	)
Enhanced tax depreciation incentive		(6,842	)		(1,003	)
Stock based compensation		1,519			170
Increase in valuation allowance		4,536			9,974
Partnership and branch loss pick-up in the United States and Canada		(4,851	)		(4,230	)
Total income tax expense	$	29,929		$	11,999

Current income tax		57,955			17,649
Deferred tax recovery		(28,026	)		(5,650	)
Total income tax expense	$	29,929		$	11,999

(1)

For the nine months ended September 30, 2010, the Company has used the United States statutory tax rate of 35% in the reconciliation of income taxes. Previously, the Company used the Canadian statutory rate in the reconciliation. This change was determined on the basis that Gran Tierra is a United States resident corporation and a reconciliation beginning with the United States statutory tax rate is more informative. The 2009 comparative income tax reconciliation has been recomputed using the United States statutory rate. This change in presentation has no impact on the income tax amounts reported in the consolidated statements of operations for the nine months ended September 30, 2009.

	As at
(Thousands of U.S. Dollars)	September 30, 2010			December 31, 2009
Deferred Tax Assets
Tax benefit of loss carryforwards	$	26,057		$	22,318
Tax basis in excess of book value		1,963			1,691
Foreign tax credits and other accruals		14,140			15,508
Capital losses		1,781			1,481
Deferred tax assets before valuation allowance		43,941			40,998
Valuation allowance		(33,765	)		(29,528	)
	$	10,176		$	11,470

Deferred tax assets - current	$	2,683		$	4,252
Deferred tax assets - long-term		7,493			7,218
		10,176			11,470

Deferred Tax Liabilities
Long-term - book value in excess of tax basis		(213,451	)		(216,625	)

Net Deferred Tax Liabilities	$	(203,275	)	$	(205,155	)

As at September 30, 2010, the Company has deferred tax assets relating to net operating loss carryforwards of $26.1 million (December 31, 2009 - $22.3 million) and capital losses of $1.8 million (December 31, 2009 - $1.5 million) before valuation allowances. Of these losses, $19.2 million (December 31, 2008 - $18.2 million) are losses generated by the foreign subsidiaries of the Company. Of the total losses, nil (December 31, 2009 - $0.1 million) will begin to expire by 2011 and $27.8 million of net operating losses (December 31, 2009 - $23.7 million) will begin to expire thereafter.

8. Accounts Payable and Accrued Liabilities

The balances in accounts payable and accrued liabilities and are comprised of the following:

	As at September 30, 2010
(Thousands of U.S. Dollars)	Colombia		Argentina		Corporate		Total
Property, plant and equipment	$	20,163	$	8,531	$	6,715	$	35,409
Payroll		3,383		136		1,495		5,014
Audit, legal, and consultants		-		108		1,441		1,549
General and administrative		1,597		460		425		2,482
Operating		39,431		1,357		-		40,788
Total	$	64,574	$	10,592	$	10,076	$	85,242

	As at December 31, 2009
(Thousands of U.S. Dollars)	Colombia		Argentina		Corporate		Total
Property, plant and equipment	$	17,723	$	844	$	213	$	18,780
Payroll		1,792		339		1,052		3,183
Audit, legal, and consultants		-		137		1,472		1,609
General and administrative		2,542		284		213		3,039
Operating		48,756		1,648		-		50,404
Total	$	70,813	$	3,252	$	2,950	$	77,015

9. Commitments and Contingencies

Leases

Gran Tierra holds three categories of operating leases: office, vehicle and housing. The Company pays monthly amounts of $196,000 for office leases, $9,000 for vehicle leases and $9,000 for certain employee accommodation leases in Colombia, Argentina, Peru, and Brazil. Future lease payments at September 30, 2010 are as follows:

	As at September 30, 2010
	Payments Due in Period
Contractual Obligations	Total		Less than 1 Year		1 to 3 years		3 to 5 years		More than 5 years
(Thousands of U.S. Dollars)
Operating leases	$	5,695	$	2,302	$	2,408	$	985	$	-
Software and Telecommunication		1,600		1,188		412		-		-
Drilling, Completion, Facility Construction and Oil Transportation Services		65,580		59,182		6,398		-		-
Total	$	72,875	$	62,672	$	9,218	$	985	$	-

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 $5.8 million.

Gran Tierra has several lawsuits and claims pending for which the Company currently cannot determine the ultimate result. Gran Tierra records costs as they are incurred or become determinable. Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position or results of operations.

10. Financial Instruments, Fair Value Measurements and Credit Risk

The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, and derivative financial instruments. The estimated fair values of the financial instruments have been determined based on the Company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. As at September 30, 2010, the fair values of financial instruments approximate their book amounts due to the short term maturity of these instruments. Most of the Company’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. The book value of the accounts receivable reflects management’s assessment of the associated credit risks.

Additionally, foreign exchange gains/losses result from the fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s deferred tax liability, a monetary liability, which is denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain/loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $116,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

The Company recognizes the fair value of its derivative instruments as assets or liabilities on the balance sheet. The Company currently does not have any financial derivatives. Previously, none of the Company's derivative instruments qualified as fair value hedges or cash flow hedges, and accordingly, changes in fair value of the derivative instruments were recognized as income or expense in the consolidated statement of operations and retained earnings with a corresponding adjustment to the fair value of derivative instruments recorded on the balance sheet.

11. Credit Facilities

Effective July 30, 2010, a subsidiary of Gran Tierra, Solana, established a credit facility with BNP Paribas for a three-year term which may be extended or amended by agreement between the parties. This reserve based facility has a maximum borrowing base up to $100 million and is supported by the present value of the petroleum reserves of the Company’s two subsidiaries with operating branches in Colombia – Gran Tierra Energy Colombia Ltd. and Solana Petroleum Exploration (Colombia) Ltd. The initial committed borrowing base is $20 million. Amounts drawn down under the facility bear interest at the USD LIBOR rate plus 3.5%. In addition, a stand-by fee of 1.50% per annum is charged on the unutilized balance of the committed borrowing base and is included in general and administrative expense. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. As at September 30, 2010, the Company had not drawn down any amounts under this facility.

12. Related Party Transactions

On February 1, 2009, the Company entered into a sublease for office space with a company (“sublessee”), of which two of Gran Tierra’s directors at the time were shareholders and directors and one such director was an officer of the sublessee. The Gran Tierra director who was an officer of the sublessee resigned as Gran Tierra’s director in August 2010. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $7,900 per month plus approximately $4,600 for operating and other expenses. The terms of the sublease were consistent with market conditions in the Calgary, Alberta, Canada real estate market.

On August 3, 2010, Gran Tierra entered into a contract with a company, of which one of Gran Tierra’s directors is a shareholder and director, for the drilling program in Peru, commencing in the fourth quarter of 2010. The terms of the contract were consistent with market conditions.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Information

This report contains forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation, statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our projected financial position and results, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct nor can we assure adequate funding will be available to execute our planned future capital program. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, those set out in Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q. Except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.

The following discussion of our financial condition and results of operations should be read in conjunction with the Financial Statements as set out in Part I – Item 1 of this Quarterly Report on Form 10-Q, as well as the financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K, filed with the U.S. Securities and Exchange Commission on February 26, 2010.

Overview

We are an independent international energy company incorporated in the United States and engaged in oil and natural gas acquisition, exploration, development and production. We are headquartered in Calgary, Alberta, Canada and operate in South America in Colombia, Argentina, Peru, and 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 June 2006.

Effective November 14, 2008, we completed the acquisition of Solana Resources Limited (“Solana”), an international resource company engaged in the acquisition, exploration, development and production of oil and natural gas in Colombia and incorporated in Alberta, Canada. At the date of acquisition, Solana held various working interests in nine blocks in Colombia including a 50% working interest in the Chaza Block, which includes the Costayaco field, and a 35% working interest in the Guayuyaco Block, which includes the Juanambu field.

Financial and Operational Highlights

(Dollar Amounts in Thousands of U.S. Dollars, Except Per Barrel and Per Share Amounts)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			% Change			2010		2009			% Change

Production - Barrels of Oil Equivalent per Day		13,536			12,945			5			13,949		12,021			16

Prices Realized - Per Barrel of Oil Equivalent	$	67.54		$	63.12			7		$	68.48	$	50.77			35

Revenue and Other Income	$	84,569		$	75,354			12		$	261,793	$	167,430			56

Net (Loss) Income	$	(3,277	)	$	(2,816	)		(16	)	$	24,054	$	(16,884	)		242

Net (Loss) Income Per Share - Basic	$	(0.01	)	$	(0.01	)		-		$	0.10	$	(0.07	)		243

Net (Loss) Income Per Share - Diluted	$	(0.01	)	$	(0.01	)		-		$	0.09	$	(0.07	)		229

Funds Flow From Operations (1)	$	37,185		$	53,127			(30	)	$	135,782	$	109,691			24

Capital Expenditures	$	47,686		$	19,124			149		$	102,046	$	63,392			61

(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Management uses this financial measure to analyze operating performance and the income (loss) generated by Gran Tierra’s principal business activities prior to the consideration of how non-cash items affect that income (loss), and believes that this financial measure is also useful supplemental information for investors to analyze operating performance and Gran Tierra’s financial results. Investors should be cautioned that this measure should not be construed as an alternative to net income (loss) or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’s method of calculating this measure may differ from other companies and therefore, it may not be comparable to similar measures used by other companies or appropriate for other purposes. Funds flow from operations, as presented, is net income (loss) adjusted for depletion, depreciation and accretion, deferred taxes, stock based compensation, unrealized loss (gain) on financial instruments and unrealized foreign exchange losses (gains).

	Three Months Ended September 30,						Nine Months Ended September 30,
Funds Flow From Operations - Non-GAAP Measure	2010			2009			2010			2009

Net (loss) income	$	(3,277	)	$	(2,816	)	$	24,054		$	(16,884	)
Adjustments to reconcile net (loss) income to funds flow from operations
Depletion, depreciation, accretion, and impairment		35,254			35,246			107,238			95,466
Deferred taxes		(9,995	)		(697	)		(28,026	)		(5,650	)
Stock-based compensation		2,064			1,198			5,424			3,483
Unrealized (gain) loss on financial instruments		-			(77	)		(44	)		294
Unrealized foreign exchange loss		13,139			20,273			27,136			32,982
Funds Flows From Operations	$	37,185		$	53,127		$	135,782		$	109,691

	As at
	September 30, 2010		December 31, 2009		% Change

Cash & Cash Equivalents	$	308,396	$	270,786		14

Working Capital (including cash & cash equivalents)	$	270,238	$	215,161		26

Property, Plant & Equipment	$	707,566	$	712,743		(1	)

Financial Highlights for the Three Months Ended September 30, 2010

In the third quarter of 2010, oil and gas production (net after royalty and inventory adjustments) averaged 13,536 barrels of oil equivalent per day (“BOEPD”) (comprised of 13,367 barrels of oil per day and 1,015 thousand cubic feet (“mcf”) of natural gas per day), an increase of 5% over the same period in 2009, due mainly to production of crude oil from three new development wells in Colombia.

·	Revenue and other income increased by 12% over the same period in 2009 due to increased production and higher oil prices.

A net loss of $3.3 million or $0.01 per share basic and diluted, compared to a net loss of $2.8 million or a loss of $0.01 per basic and diluted share in the third quarter of 2009. Increased revenue, due to an 8% increase in realized oil prices, was more than offset by increased operating and general and administrative expenses (“G&A”) in the current quarter compared to the same period in the prior year.

Funds flow from operations of $37.2 million for the three months ended September 30, 2010 decreased 30% over the same quarter in the prior year primarily as a result of increased operating costs which more than offset increased production from three additional development wells drilled in Colombia and an 8% improvement in the oil price received for production.

Oil and gas property expenditures for the third quarter of 2010 include expenditures for testing and completing the Moqueta – 1 exploration well, and the successful drilling of the Moqueta– 2 and – 3 delineation wells in the Chaza block in Colombia, facility construction in the Chaza block, seismic acquisition in Peru, preparation for sidetrack drilling operations for the VM.x–1001 gas well in Argentina, and our initial exploration and production transaction in Brazil.

Our cash and cash equivalents of $308.4 million at September 30, 2010 increased from $270.8 million at December 31, 2009 as a result of cash provided by operating activities of $101.4 million, and the issuance of shares upon the exercise of warrants and stock options of $22.9 million, partially offset by year-to-date capital expenditures (adjusted for associated non-cash working capital) and other investing activities of $86.7 million.

Working capital (including cash and cash equivalents) was $270.2 million at September 30, 2010, which is a $55.1 million increase from December 31, 2009, due mainly to the increase in our cash position as well as higher accounts receivable from year end. Accounts receivable at any period end other than year end include two months of oil sales in Colombia. Year end accounts receivable traditionally include less than one month of oil sales due to year end settlement of outstanding amounts.

·	Property, plant and equipment as at September 30, 2010 was $707.6 million, a $5.2 million decrease from December 31, 2009, primarily as a result of depletion, depreciation and accretion (“DD&A”), partially offset by capital additions.

Financial Highlights for the Nine Months Ended September 30, 2010

·	During the first three quarters of 2010, oil and gas production (net after royalty and inventory adjustments) averaged 13,949 BOEPD, an increase of 16% over the same period in 2009, due mainly to production of crude oil from five additional development wells in Colombia.

·	Revenue and other income increased by 56% over the same period in 2009 due to increased production and higher oil prices.

Net income of $24.1 million or $0.10 per share basic and $0.09 per share diluted, compares to a net loss of $16.9 million, or a net loss of $0.07 per share basic and diluted in 2009. Net income was positively impacted by a 35% increase in realized oil prices in the nine months compared to the same period in the prior year. Net income was also impacted by a $33.7 million foreign exchange loss (compared to a $32.4 million loss recorded for the same period in 2009), of which $27.1 million is an unrealized non-cash foreign exchange loss, primarily resulting from the translation of a deferred tax liability.

Funds flow from operations for the nine months ended September 30, 2010 increased to $135.8 million, a 24% increase over the same period in the prior year, primarily as a result of increased production from five additional development wells drilled in Colombia and a 35% improvement in the oil price received for production.

Oil and gas property expenditures for the nine months ended September 30, 2010 include expenditures for the successful drilling of the Juanambu – 2 well in the Guayuyaco block in Colombia, the successful drilling of the Moqueta – 1, – 2, – 3, and Costayaco – 11 wells in the Chaza block in Colombia, facility construction in the Chaza block, seismic acquisition in Peru, preparation for sidetrack drilling operations for the VM.x–1001 gas well in Argentina, and our initial exploration and production transaction in Brazil.

Operational Highlights for the Nine Months Ended September 30, 2010

· Expanded Exploration Portfolio in Peru

In September 2010, we acquired a 20% working interest, in 6.7 million gross acres, in three blocks (123, 124, and 129) in Peru. The agreement was entered into with Burlington Resources Peru Limited, Sucursal Peruana, a wholly owned subsidiary of ConocoPhillips Company. These three blocks are contiguous to blocks 122 and 128, in Peru, in which we hold a 100% working interest. For the purpose of enhancing the regional interpretation of the area, the terms of the transaction include sharing technical data derived from the seismic and drilling program on blocks 122 and 128.

· Initial Exploration and Production Transaction in Brazil

In August 2010, we announced our initial exploration and production transaction in Brazil. An agreement was signed with Alvorada Petroleo S.A. for a 70% working interest in four blocks (T-129, -142, -155, and -224) in the on-shore Reconcavo Basin in Brazil, where we would be operator. This transaction is subject to obtaining the customary regulatory approval from Brazil’s Agencia Nacional de Petroleo Gas Natural e Biocombustiveis (“ANP”).

· Oil Discovery at Moqueta in Colombia

In June 2010, we confirmed an oil discovery at the Moqueta-1 exploration well in the Chaza Block in Colombia. Initial testing without a pump flowed 349 barrels of oil per day “BOPD”, in addition to successful gas testing in a shallower reservoir interval. Subsequent drilling and testing of the Moqueta-2 delineation well in August 2010 produced well flow rates, without pumps, of 850 BOPD. We anticipate the initiation of long term oil testing and early production in the first quarter of 2011.

· Environmental Impact Assessment (“EIA”) Approval in Peru

The EIA approval for seismic and drilling operations was received for Block 128, in August 2010, and for Block 122, in September 2010; both blocks are in the Marañon Basin in Peru. We concluded 260 kilometers of 2D seismic on Block 128 in October 2010 and anticipate moving to Block 122 to begin seismic acquisition operations in the fourth quarter of 2010. We anticipate the drilling of up to four wells in Peru to commence in the fourth quarter of 2010 and continue into early 2011.

· Successful Production Testing of Costayaco - 11

In June 2010, we completed logging operations and initiated production testing of Costayaco – 11. Costayaco – 11 was drilled in the northern portion of the Costayaco field in Colombia, and was tied in and put on production in early July. The well is currently producing from the Caballos formation and is expected to be used as a water-injector in the future to provide pressure maintenance in the T-Sandstone reservoir.

· Successful Acreage Awards in Colombia

In June 2010, we were awarded three blocks (Putumayo 10, Cauca 6 and 10) in the 2010 Colombia Bid Round administered by Colombia’s National Hydrocarbons Agency (“ANH”). Bid contracts are pending final approval by ANH. We believe Putumayo 10 will enable us to leverage existing knowledge of our Piedemonte Norte and Piedemonte Sur Blocks, and believe that Cauca 6 and 10 provide new frontier exploration opportunities for the company.

· Commenced Workover and Sidetrack Drilling Operations for the VM.x–1001 Gas Well in Argentina

At the end of June 2010 we began mobilization of the drilling rig for the VM.x–1001 gas well in the Valle Morado Block in Argentina. Workover and sidetrack drilling operations of this re-entry well, in the Noroeste Basin, commenced in August 2010.

· Successful Production Testing of Juanambu - 2

In February 2010, we completed logging operations of the Juanambu - 2 development well in the Juanambu field discovered in 2007 in the Guayuyaco Block in Colombia. Testing of the well was completed early in March 2010 and the well came on production later in the month.

· Dantayaco -1 Exploration Well

We completed drilling of the Dantayaco - 1 exploration well in the Chaza Block, in the Putumayo basin of Colombia, at the end of 2009. During testing, only formation water was recovered and the well was plugged and abandoned on January 3, 2010.

Consolidated Results of Operations

	Three Months Ended September 30,									Nine Months Ended September 30,
Consolidated Results of Operations	2010			2009			% Change			2010			2009			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	84,110		$	75,171			12		$	260,759		$	166,606			57
Interest		459			183			151			1,034			824			25
		84,569			75,354			12			261,793			167,430			56

Operating expenses		19,401			9,099			113			39,028			25,063			56
Depletion, depreciation, accretion, and impairment		35,254			35,246			-			107,238			95,466			12
General and administrative expenses		10,977			7,076			55			27,848			19,226			45
Foreign exchange loss		16,320			18,867			(13	)		33,740			32,353			4
Derivative financial instruments (gain) loss		-			(77	)		-			(44	)		207			(121	)
		81,952			70,211			17			207,810			172,315			21

Income (loss) before income taxes		2,617			5,143			(49	)		53,983			(4,885	)		1,205
Income tax expense		(5,894	)		(7,959	)		(26	)		(29,929	)		(11,999	)		149
Net (loss) income	$	(3,277	)	$	(2,816	)		16		$	24,054		$	(16,884	)		242

Production, Net of Royalties

Oil and NGL's ("bbl") (1)	1,229,768	1,190,954	3	3,775,704	3,273,597	15
Natural gas ("mcf") (1)	93,384	-	-	193,452	49,028	295
Total production ("boe") (1) (2)	1,245,332	1,190,954	5	3,807,946	3,281,768	16

Average Prices

Oil and NGL's ("per bbl")	$	68.12	$	63.12	8	$	68.87	$	50.84	35
Natural gas ("per mcf")	$	3.64	$	-	-	$	3.85	$	3.91	(2	)

Consolidated Results of Operations ("per boe")

Oil and natural gas sales	$	67.54		$	63.12		7		$	68.48		$	50.77		35
Interest		0.37			0.15		147			0.27			0.25		8
		67.91			63.27		7			68.75			51.02		35

Operating expenses		15.58			7.64		104			10.25			7.64		34
Depletion, depreciation, accretion, and impairment		28.31			29.59		(4	)		28.16			29.09		(3	)
General and administrative expenses		8.81			5.94		48			7.31			5.86		25
Foreign exchange loss		13.10			15.84		(17	)		8.86			9.86		(10	)
Derivative financial instruments (gain) loss		-			(0.06	)	-			(0.01	)		0.06		117
		65.80			58.95		12			54.57			52.51		4

Income (loss) before income taxes		2.11			4.32		(51	)		14.18			(1.49	)	1,052
Income tax expense		(4.73	)		(6.68	)	(29	)		(7.86	)		(3.66	)	115
Net (loss) income	$	(2.62	)	$	(2.36	)	11		$	6.32		$	(5.15	)	223

(1) Gas volumes are converted to barrel of oil equivalent (“boe”) at the rate of six thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which the rate is not necessarily indicative of the relationship of oil and gas prices. At December 31, 2009, Gran Tierra changed from the conversion of gas volumes to boe at a rate of 20 mcf of gas per barrel of oil to provide volume information consistent with standard industry practice and to reflect natural gas’s relative energy content to a barrel of oil. As a result, the boe volumes presented, for the nine months ended September 30, 2009, have increased by 5,720 boe from those volumes previously disclosed. Natural gas liquids (“NGL”) volumes are converted to boe on a one-to-one basis with oil.

(2) Production represents production volumes adjusted for inventory changes.

Consolidated Results of Operations for the Three and Nine Months Ended September 30, 2010 compared to the Results for the Three and Nine Months Ended September 30, 2009

Net loss of $3.3 million was recorded for the three months ended September 30, 2010, compared to a net loss of $2.8 million for the same quarter in 2009. Higher oil revenues due to increased production and higher prices were more than offset by increased operating and G&A expenses for the current quarter. The net loss for the third quarter of 2010 included a foreign exchange loss of $16.3 million, of which $13.1 million was an unrealized non-cash foreign exchange loss. The net loss for the third quarter of 2009 included a $18.9 million foreign exchange loss, of which $20.3 million was an unrealized non-cash foreign exchange loss. Net income of $24.1 million, or $0.10 per share basic and $0.09 per share diluted, was recorded for the nine months ended September 30, 2010 compared to a net loss of $16.9 million, or $0.07 per share, for the same period in 2009. Oil and natural gas sales for the nine months ended September 30, 2010 increased by $94.2 million from the same period in 2009, resulting from higher production and higher realized oil prices, which more than offset an increase of $11.8 million in DD&A, and increases in operating expenses and G&A expenses.

Crude oil and NGL production, net after royalties, for the three months ended September 30, 2010 increased to 1,229,768 barrels (3,775,704 barrels for the first nine months of 2010) compared to 1,190,954 barrels for the same quarter in 2009 (3,273,597 barrels for the first nine months of 2009) due mainly to increased production from our Colombia operations. Average realized crude oil prices for the current quarter increased to $68.12 per barrel ($68.87 for the first nine months of 2010) from $63.12 per barrel for the three months ended September 30, 2009 ($50.84 per barrel for the first nine months of 2009), reflecting higher West Texas Intermediate (“WTI”) oil prices.

Revenue and interest increased 12% to $84.6 million for the three months ended September 30, 2010 compared to $75.4 million in the same quarter in 2009 due to increased crude oil production in Colombia and an increase of 8% in realized crude oil prices. For the nine months ended September 30, 2010, revenue and interest increased 56% to $261.8 million compared to the same period in 2009 due to increased crude oil production in Colombia and an increase of 35% in realized crude oil prices.

Operating expenses for the third quarter of 2010 amounted to $19.4 million, a 113% increase from the same period in 2009. Operating expenses for the nine months ended September 30, 2010 increased to $39.0 million a 56% increase from the same period last year. The increase in operating expenses is due to expanded operations, increased workovers, increased transportation costs, and increased production levels in Colombia. For the three months ended September 30, 2010, operating expenses on a boe basis increased by 104% to $15.58 due to the impact of higher costs and increased workovers which more than offset increased production. A smaller increase was recorded for the nine months ended September 30, 2010 with operating expenses of $10.25 per boe compared to $7.64 per boe, a 34% increase from the same period in 2009 due to the same reasons cited above.

DD&A expense of $35.3 million for the current quarter was comparable to the DD&A expense recorded in the same quarter in 2009 due to similar production levels. However, for the first nine months of 2010, DD&A expense increased by 12% to $107.2 million due to increased production levels in Colombia and a $3.7 million ceiling test impairment loss in our Argentina cost center recorded in the first quarter of 2010. On a boe basis, DD&A for the third quarter was $28.31 which is 4% lower compared to the same quarter in 2009, and decreased 3% to $28.16 for the nine months ended September 30, 2010 compared to the same period in 2009 due to higher proved reserves.

G&A expenses of $11.0 million and $27.8 million for the three month and nine months ended September 30, 2010, respectively, were 55% and 45% higher, respectively, than the same period in 2009 primarily due to increased employee related costs reflecting expanded operations. G&A expenses per boe increased 48% to $8.81 for the current quarter, compared to $5.94 for the third quarter of 2009, and increased by 25% to $7.31 for the first nine months ended September 30, 2010 compared to $5.86 for the same period in 2009 due to the same reasons cited above but partially offset by increased production levels.

The foreign exchange loss of $16.3 million for the third quarter of 2010 (of which $13.1 million is an unrealized non-cash foreign exchange loss) and the foreign exchange loss of $33.7 million for the first three quarters of 2010 (of which $27.1 million is an unrealized non-cash foreign exchange loss) primarily represent foreign exchange gains and losses resulting from the translation of a deferred tax liability. In the third quarter of 2009, a $18.9 million foreign exchange loss was recorded (of which $20.3 million was an unrealized non-cash foreign exchange loss) and for the first three quarters of 2009 the foreign exchange loss amounted to $32.4 million (of which $33.0 million was an unrealized non-cash foreign exchange loss) primarily as a result of translation of deferred taxes.

Income tax expense for the three months ended September 30, 2010 amounted to $5.9 million compared to an income tax expense of $8.0 million recorded in the same period in 2009. An income tax expense of $29.9 million was recorded for the nine months ended September 30, 2010 compared to an income tax expense of $12.0 million recorded for the same period in 2009. The increase of $17.9 million in income tax expense over the same nine month period in 2009 is primarily due to higher income before income taxes. The effective tax rate for the nine months ended September 30, 2010 is 55%. The variance from the 35% U.S. statutory rate for the nine months ended September 30, 2010 results from non-deductible foreign currency translation losses as described above and an increase in valuation allowances taken on losses incurred in the U.S., Canada, Peru and Brazil, offset by enhanced tax depreciation in Colombia on oil and gas capital expenditures. The variance from the 35% U.S. statutory rate for the nine months ended September 30, 2009 is primarily attributable to non-deductible foreign currency translation losses in each of the respective jurisdictions and recognition of valuation allowances taken on losses incurred in the U.S., Canada, and Peru.

Segmented Results of Operations

Our operations are carried out in Colombia, Argentina, Peru, and Brazil, and we are headquartered in Calgary, Alberta, Canada. Our reportable segments include Colombia, Argentina and Corporate with the latter including the results of our initial activities in Peru and Brazil. For the three and nine months ended September 30, 2010, Colombia generated 96% of our revenue and other income. For the three and nine months ended September 30, 2009, Colombia generated 95% and 94%, respectively, of our revenue and other income.

Segmented Results – Colombia

	Three Months Ended September 30,							Nine Months Ended September 30,
Segmented Results of Operations – Colombia	2010		2009		% Change			2010		2009		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	80,731	$	71,385		13		$	250,767	$	156,257		60
Interest		301		31		871			520		352		48
		81,032		71,416		13			251,287		156,609		60

Operating expenses		17,090		7,242		136			32,480		20,292		60
Depletion, depreciation and accretion		33,916		33,630		1			99,243		90,565		10
General and administrative expenses		4,391		2,777		58			11,190		7,396		51
Foreign exchange loss		17,330		19,812		(13	)		34,220		32,986		4
		72,727		63,461		15			177,133		151,239		17

Segment income before income taxes	$	8,305	$	7,955		(4	)	$	74,154	$	5,370		1,281

Production, Net of Royalties

Oil and NGL's ("bbl") (1)	1,162,961	1,107,265	5	3,567,377	3,017,078	18
Natural gas ("mcf") (1)	93,384	-	-	193,452	49,028	295
Total production ("boe") (1) (2)	1,178,525	1,107,265	6	3,599,619	3,025,249	19

Average Prices

Oil and NGL's ("per bbl")	$	69.12	$	64.47	7	$	70.08	$	51.73	35
Natural gas ("per mcf")	$	3.66	$	-	-	$	3.88	$	3.91	(1	)

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	68.50	$	64.47	6		$	69.66	$	51.65	35
Interest		0.26		0.03	767			0.14		0.12	17
		68.76		64.50	7			69.80		51.77	35

Operating expenses		14.50		6.54	122			9.02		6.71	34
Depletion, depreciation and accretion		28.78		30.37	(5	)		27.57		29.94	(8	)
General and administrative expenses		3.73		2.51	49			3.11		2.44	27
Foreign exchange loss		14.70		17.89	(18	)		9.51		10.90	(13	)
		61.71		57.31	8			49.21		49.99	(2	)

Segment income before income taxes	$	7.05	$	7.19	(2	)	$	20.59	$	1.78	1,057

(1)

Gas volumes are converted to barrel of oil equivalent (“boe”) at the rate of six thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which the rate is not necessarily indicative of the relationship of oil and gas prices. At December 31, 2009, Gran Tierra changed from the conversion of gas volumes to boe at a rate of 20 mcf of gas per barrel of oil to provide volume information consistent with standard industry practice and to reflect natural gas’s relative energy content to a barrel of oil. As a result, the boe volumes presented, for the nine months ended September 30, 2009, have increased by 5,720 boe from those volumes previously disclosed. Natural gas liquids (“NGL”) volumes are converted to boe on a one-to-one basis with oil.

(2)

Production represents production volumes adjusted for inventory changes.

Segmented Results of Operations – Colombia for the Three and Nine Months Ended September 30, 2010 compared to the Results for the Three and Nine Months Ended September 30, 2009

For the three months ended September 30, 2010, income before income taxes from Colombia amounted to $8.3 million compared to income before income taxes of $8.0 million recorded for the same period in 2009. This is mainly the result of higher oil revenues due to increased oil production and higher oil prices, partially offset by higher operating expenses due to increased Colombian operations and workovers, and increased general and administrative expenses from expanded activities. The results for the three months ended September 30, 2010 include a $17.3 million foreign exchange loss, $13.1 million of which was a non-cash foreign exchange loss, primarily due to the translation of deferred taxes. For the first nine months of 2010, income before income taxes was $74.2 million compared to income before income taxes of $5.4 million recorded in the same period in 2009 primarily due to higher revenue. A $34.2 million foreign exchange loss, of which $27.0 million is an unrealized non-cash foreign exchange loss, a $12.2 million increase in operating expenses, and a $8.9 million increase in DD&A partially offset higher revenues in the period. On a per barrel basis, the pre-tax income for the current quarter was $7.05 ($20.59 for the first nine months of 2010) versus pre-tax income of $7.19 for the three months ended September 30, 2009 (pre-tax income of $1.78 for the first nine months of 2009).

For the three months ended September 30, 2010, production of crude oil and NGLs, net after royalties, increased by 5% to 1,162,961 barrels compared to 1,107,265 barrels for the same period in 2009 due to increased production from three new development wells in Colombia. These three new wells include one new development well (Juanambu -2) in the Guayuyaco Block and two new development wells (Costayaco – 10 and –11) in the Costayaco field. The production for the first nine months of 2010 amounted to 3,567,377 barrels compared to 3,017,078 barrels, an increase of 18% from the same period last year. This year-to-date increase is mostly due to production from five additional development wells (Juanambu -2, Costayaco – 8, –9, –10, and –11). These production levels are after government royalties ranging from 8% to 26% and third party royalties of 2% to 10%. Crude oil production, net after royalties, for 2010 was reduced by additional government royalties payable as a result of achieving cumulative gross field production of five million barrels in the Costayaco field on September 10, 2009.

In the third quarter of 2010, sections of the Ecopetrol operated Trans Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 22 days. Our production in the first nine months of 2009 was impacted by political and economic factors in Colombia. We temporarily suspended production operations in the Costayaco and Juanambu oil fields due to a general strike in the region where our operations are located from November 24, 2008 to January 12, 2009. In the third quarter of 2009, sections of the Ecopetrol operated Tran Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol. As a result of these factors, deliveries to Ecopetrol in 2009 were reduced during the first 10 days of the first quarter, for 14 days in the second quarter, and for 27 days in the third quarter.

Revenue and interest for the three and nine months ended September 30, 2010 increased by 13% to $81.0 million, and by 60% to $251.3 million, respectively, from the comparable prior year periods. Revenue and interest were positively impacted by an increase in net realized crude oil prices in 2010 compared to 2009 as well as increased production. The average net realized prices for crude oil, which are based on WTI prices, increased by 7% to $69.12 per barrel for the three months ended September 30, 2010 compared to the same period last year. For the first nine months of this year, the average realized price increased by 35% to $70.08 per barrel from the same period last year.

As a result of achieving cumulative gross field production of five million barrels in our Costayaco field during the month of September 2009, Gran Tierra is now subject to an additional government royalty payable. This royalty is calculated on 30% of the field production revenue over an inflation adjusted trigger point. That trigger point for Costayaco crude oil is $32.13 for 2010. Production revenue for this calculation is based on production volumes net of other government royalty volumes. Average government royalties at Costayaco with gross production of 17,000 barrels of oil per day (“BOPD”) and $80 WTI per barrel are approximately 25.5%, including the additional government royalty of approximately 18.0%. The ANH sliding scale royalty at 17,000 BOPD is approximately 9.2% and this royalty is deductible prior to calculating the additional government royalty.

Operating expenses for the three months ended September 30, 2010 increased to $17.1 million from $7.2 million in the same period last year. For the nine months ended September 30, 2010 operating expenses increased to $32.5 million compared to $20.3 million in the same period in 2009. The increased operating expenses resulted from the increase in production, transportation, and workover expenses at Costayaco. On a per barrel basis, operating expenses for the third quarter of 2010 increased to $14.50 compared to $6.54 incurred for the same period last year ($9.02 for the first nine months of 2010 versus $6.71 in the same period last year) reflecting the increase in workover expenses per barrel as our operations have expanded. The additional government royalties for 2010 decreased crude oil production net after royalties and as a result increased operating expense per boe.

For the quarter ended September 30, 2010, DD&A expense increased to $33.9 million compared to $33.6 million in the same period in 2009 and increased to $99.2 million for the first three quarters of 2010 compared to $90.6 million for the same period in 2009. Increased production levels coupled with a higher depletable cost base partially offset by higher crude oil proved reserves, accounted for the increase in DD&A expense. On a per boe basis, the DD&A expense in Colombia decreased by 5% to $28.78 for the third quarter and by 8% to $27.57 for the first nine months of 2010 compared with the same periods last year due to higher proved reserves.

An increased level of employee related costs reflecting expanded operations and higher stock-based compensation expense resulted in G&A expense increasing to $4.4 million for the three months ended September 30, 2010 from $2.8 million incurred for the same period in 2009. For the nine months ended September 30, 2010, G&A increased to $11.2 million from $7.4 million incurred for the first nine months of 2009, for the same reasons cited above. On a per barrel basis, G&A expense increased by 49% to $3.73 from $2.51 for the third quarter of 2010 compared with the same period in 2009 due to increased costs partially offset by higher production. For the nine months ended September 30, 2010, G&A expense per boe increased by 27% to $3.11 from $2.44 for the first nine months of 2009. G&A expenses per boe also increased in 2010 due to the impact of additional government royalties on net after royalty production.

For the three months ended September 30, 2010, the foreign exchange loss of $17.3 million, of which $13.1 million is an unrealized non-cash foreign exchange loss (third quarter of 2009 - $19.8 million loss, of which $19.6 million was an unrealized loss) resulted primarily from the translation of a deferred tax liability recognized on the purchase of Solana. For the nine months ended September 30, 2010, the foreign exchange loss was $34.2 million, of which $27.0 million is an unrealized non-cash foreign exchange loss (first three quarters of 2009 - $33.0 million loss, of which $32.2 million was an unrealized loss) on the translation of deferred taxes. This deferred tax liability, a monetary liability, is denominated in Colombian pesos, 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. The decline of 12% in the U.S. dollar against the Colombian peso in the first nine months of 2010 (6% in the three months ended September 30, 2010) resulted in the foreign exchange loss. This compares to a 14% decline in the U.S. dollar against the Colombian peso for the nine months ended September 30, 2009 (11% in the three months ended September 30, 2009) which resulted in the foreign exchange loss recorded in that period. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $116,000 for each one peso decrease in the exchange rate of the Colombian peso to one US dollar.

Capital Program - Colombia

Gran Tierra’s focus in Colombia for the first three quarters of 2010 was the 2010 exploration and development drilling program, including the drilling of the Moqueta -1 exploration well, Moqueta -2, and -3 delineation appraisal wells, and the Costayaco -11 development well, all in the Chaza block. In addition, we continued the development of the Costayaco field with additional facilities and equipment. In support of this focus, our capital expenditures in Colombia amounted to $22.1 million and $68.5 million, respectively, for the three and nine months ended September 30, 2010.

Segmented Capital Expenditures – Colombia		Three Months Ended,		Nine Months Ended,
Block and Activity		September 30, 2010		September 30, 2010
(Millions of U.S. Dollars)

Chaza	Costayaco facilities and site preparation and drilling for Costayaco -11, Moqueta -1, -2, -3, -4, and Pacayaco -1	$	17.8	$	46.1
Rio Magdalena	Popa-3 drilling		2.6		2.6
Guayuyaco	Juanambu -2 drilling and facilities		0.9		6.1
Garibay	Completion of 3D seismic program and Jilguero -1 drilling		0.7		5.9
Rumiyaco	Commencement of 3D seismic		0.1		4.6
Piedemonte Sur	Rig mobilization for Taruka -1 well		-		1.0
Azar	2D and 3D seismic programs		-		1.4
Piedemonte Norte	Commencement of 3D seismic		-		0.3
Magangue	Guepaje facilities		-		0.5

Segmented Capital Expenditures – Colombia		$	22.1	$	68.5

For comparison, during the three months ended September 30, 2009, we spent $17.0 million on capital projects and for the nine months ended September 30, 2009 we spent $58.4 million on capital projects.

Segmented Capital Expenditures - Colombia		Three Months Ended,		Nine Months Ended,
Block and Activity		September 30, 2009		September 30, 2009
(Millions of U.S. Dollars)

Chaza	Drilled and tested Costayaco -6, -7, -8, -9, begin drilling of Costayaco -10, 2D seismic, additional facilities and equipment	$	11.6	$	33.4
Rio Magdalena	Completed long-term testing of Popa-2 well		1.4		2.7
San Pablo	Commenced 3D seismic program		1.2		2.2
Azar	Commenced 2D and 3D seismic programs		1.0		1.8
Guachiria Sur	Acquired 115 km2 of 3D seismic		-		3.7
Guachiria Norte	Drilled an exploration well, Puinaves-2, which was dry		-		5.8
Guachiria	Completed acquisition of 115 km2 of 3D seismic		-		1.1
Garibay	Completed acquisition of 110 km2 of 3D seismic		-		2.6
Leasehold improvements			0.3		2.0
Capitalized G&A and other			1.5		3.1

Segmented Capital Expenditures – Colombia		$	17.0	$	58.4

Segmented Results – Argentina

	Three Months Ended September 30,									Nine Months Ended September 30,
Segmented Results of Operations - Argentina	2010			2009			% Change			2010			2009			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	3,379		$	3,786			(11	)	$	9,992		$	10,349			(3	)
Interest		-			34			-			19			84			(77	)
		3,379			3,820			(12	)		10,011			10,433			(4	)

Operating expenses		2,266			1,856			22			6,408			4,738			35
Depletion, depreciation and accretion		1,208			1,538			(21	)		3,999			4,671			(14	)
Impairment of carrying value of oil and natural gas properties		-			-			-			3,700			-			-
General and administrative expenses		353			546			(35	)		1,958			1,511			30
Foreign exchange (gain) loss		(43	)		(510	)		(92	)		104			90			16
		3,784			3,430			10			16,169			11,010			47

Segment (loss) income before income taxes	$	(405	)	$	390			(204	)	$	(6,158	)	$	(577	)		967

Production, Net of Royalties

Oil and NGL's ("bbl") (1) (2)		66,807			83,689			(20	)		208,327			256,519			(19	)

Average Prices

Oil and NGL's ("per bbl")	$	50.58		$	45.24			12		$	47.96		$	40.34			19

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	50.58		$	45.24			12		$	47.96		$	40.34			19
Interest		-			0.41			-			0.09			0.33			(73	)
		50.58			45.65			11			48.05			40.67			18

Operating expenses		33.92			22.18			53			30.76			18.47			66
Depletion, depreciation and accretion		18.08			18.38			(2	)		19.20			18.21			5
Impairment of carrying value of oil and natural gas properties		-			-			-			17.76			-			-
General and administrative expenses		5.28			6.52			(19	)		9.40			5.89			60
Foreign exchange (gain) loss		(0.64	)		(6.09	)		(89	)		0.50			0.35			43
		56.64			40.99			38			77.62			42.92			81

Segment (loss) income before income taxes	$	(6.06	)	$	4.66			230		$	(29.57	)	$	(2.25	)		1,214

(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, 2010 compared to the Results for the Three and Nine Months Ended September 30, 2009

For the three months ended September 30, 2010, the pre-tax loss from Argentina was $0.4 million compared to pre-tax income of $0.4 million recorded in the same period in 2009. The loss resulted from lower production levels and increased operating costs, offset partially by increased prices and lower DD&A. For the nine months ended September 30, 2010, the pre-tax loss was $6.2 million compared to $0.6 million of pre-tax loss recorded in the same period last year. Higher losses resulted from lower production levels, increased operating costs and G&A, and a $3.7 million ceiling test impairment loss recorded in the first quarter of 2010, offset partially by increased prices and lower DD&A.

Crude oil and NGL production, net after 12% royalties, decreased to 66,807 barrels for the three months ended September 30, 2010 compared to 83,689 barrels for the same period in 2009. For the nine months ended September 30, 2010, production levels decreased by 19% to 208,327 barrels compared to 256,519 barrels produced in the same period in 2009. The decrease resulted from increased workover related well downtime compared to the prior year.

Due to the local regulatory regimes, the price we currently receive for production from our blocks is approximately $52 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, 2010. We are working with other oil and gas producers in the area, as well as Refiner S.A. and provincial governments, to lobby the federal government for change.

A 12% improvement in regulated crude oil prices was more than offset by lower production levels which resulted in our revenues decreasing by 11% to $3.4 million in the three months ended September 30, 2010 from $3.8 million for the same period in 2009. For the nine months ended September 30, 2010, revenue levels were $10.0 million a decrease of 3% from the comparable prior period. A 19% decline in production levels was offset by a 19% increase in regulated crude oil prices for the nine months ended September 30, 2010.

Operating expenses for the three months ended September 30, 2010, increased to $2.3 million ($33.92 per boe) compared to $1.9 million ($22.18 per boe) incurred in the same quarter last year. Operating expenses for the first three quarters of 2010 increased to $6.4 million ($30.76 per boe) compared to $4.7 million ($18.47 per boe) for the same period a year ago. The increase in operating costs resulted from higher fixed costs during the first nine months of 2010. Higher fixed costs and lower production volumes resulted in the increase in operating costs on a per boe basis.

DD&A expense for the three and nine months ended September 30, 2010 was $1.2 million and $4.0 million, respectively, a decrease from the $1.5 million and $4.7 million recorded in the same period of 2009, respectively. On a per boe basis, DD&A for the three months ended September 30, 2010 decreased to $18.08 from $18.38 recorded in the same period last year due to lower production. For the first three quarters of 2010 DD&A on a per boe basis increased to $19.20 from $18.21 recorded in the same period a year ago. The impact of lower proved reserves more than offset a decreasing proved depletable cost base. In addition, the first quarter of 2010 included a $3.7 million ceiling test impairment loss in our Argentina cost center.

Capital Program - Argentina

Capital expenditures for the three months ended September 30, 2010, amounted to $12.3 million bringing the total expenditures in the region for the first nine months of 2010 to $16.8 million. The capital expenditures for the three and nine months ended September 30, 2010 mainly related to facility construction, the acquisition of seismic data, and drilling preparations for the VM.x-1001 gas well in the Valle Morado block. Capital expenditures in Argentina for the three months ended September 30, 2009, were $1.9 million ($3.2 million for the nine months ended September 30, 2009). These costs included facilities upgrade costs in the Palmar Largo area and exploration land lease costs and capitalized G&A including non-cash stock based compensation expense.

Segmented Results – Corporate

	Three Months Ended September 30,								Nine Months Ended September 30,
	2010			2009			% Change		2010			2009			% Change
Segmented Results of Operations - Corporate
(Thousands of U.S. Dollars)
Interest	$	158		$	118			34	$	495		$	388			28

Operating expenses		45			1			-		140			33			324
Depletion, depreciation and accretion		130			78			67		296			230			29
General and administrative expenses		6,233			3,753			66		14,700			10,319			42
Derivative financial instruments loss (gain)		-			(77	)		-		(44	)		207			(121	)
Foreign exchange gain		(967	)		(435	)		122		(584	)		(723	)		(19	)
		5,441			3,320			64		14,508			10,066			44

Segment loss before income taxes	$	(5,283	)	$	(3,202	)		65	$	(14,013	)	$	(9,678	)		45

Segmented Results of Operations - Corporate

In addition to the expenditures associated with the maintenance of Gran Tierra’s headquarters in Calgary, Alberta, Canada, and cost of compliance and reporting under securities regulations, the results of the Corporate Segment include the results of our 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 to manage expanded operations and higher stock-based compensation expense due to increased stock option grants associated with increased staff. For the first three quarters of 2010, G&A expenses included $1.6 million and $0.9 million from the Brazil and Peru business units, respectively. This compares to nil and $0.2 million from the Brazil and Peru business units, respectively, in the same period of 2009.

Capital Program – Corporate

The capital expenditures for the Corporate Segment during the three months ended September 30, 2010 were $13.3 million, bringing the total expenditures for the first nine months of 2010 to $16.8 million. The 2010 year-to-date capital expenditures for the Corporate Segment included expenditures of $9.2 million for Peru on our exploration blocks 122 and 128. The year-to-date expenditures incurred on the Peru blocks mainly related to drilling feasibility and geological studies, as well as $7.0 million of seismic acquisition costs on block 128. For comparison, for the first nine months ended September 30, 2009, capital expenditures included $1.5 million related to drilling feasibility and geological studies on the Peru blocks. The 2010 year-to-date capital expenditures for the Corporate Segment also included expenditures of $6.0 million related to our initial exploration and production transaction in Brazil.

Liquidity and Capital Resources

At September 30, 2010, we had cash and cash equivalents of $308.4 million compared to $270.8 million at December 31, 2009. We believe that our cash position 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.

The costless collar we had entered into in accordance with the terms of the credit facility with Standard Bank Plc terminated in February 2010 as a result of the expired credit facility.

On July 30, 2010 Gran Tierra’s subsidiary, Solana, entered into a credit facility with BNP Paribas. The facility is a reserve base lending agreement for up to $100 million, with an initial committed borrowing base of $20 million. This credit facility is secured against the reserves of our two subsidiaries with operating branches in Colombia – Gran Tierra Energy Colombia Ltd. and Solana Petroleum Exploration (Colombia) Ltd.

Cash Flows

During the nine months ended September 30, 2010, our cash and cash equivalents increased by $37.6 million as cash inflows from operations of $101.4 million and from financing activities of $22.9 million more than offset cash outflows for investing activities of $86.7 million. Net cash provided by operating activities was affected by the increase in crude oil production and increase in prices, offset by the increases in receivables related to oil sales.

During the nine months ended September 30, 2009, our cash and cash equivalents decreased by $25.2 million as the cash inflows from operating activities 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 which was more than offset by the decrease in prices as well as increases in receivables related to oil sales.

Off-Balance Sheet Arrangements

As at September 30, 2010, we had no off-balance sheet arrangements.

Contractual Obligations

Gran Tierra holds three categories of operating leases, namely office, vehicle and housing. Future lease payments and other contractual obligations at September 30, 2010 are as follows:

	As at September 30, 2010
	Payments Due in Period
Contractual Obligations	Total		Less than 1 Year		1 to 3 years		3 to 5 years		More than 5 years
(Thousands of U.S. Dollars)
Operating leases	$	5,695	$	2,302	$	2,408	$	985	$	-
Software and Telecommunication		1,600		1,188		412		-		-
Drilling, Completion, Facility Construction and Oil Transportation Services		65,580		59,182		6,398		-		-
Total	$	72,875	$	62,672	$	9,218	$	985	$	-

Contractual commitments have increased $39.6 million from December 31, 2009 as a result of entering into third party facility construction, oil transportation and drilling rig commitment contracts in Colombia, Argentina, and Peru.

Related Party Transactions

In connection with the Solana acquisition, we acquired additional office space of 4,441 square feet used by Solana as its headquarters in Calgary. The lease payments under the lease are $10,100 per month and operating and other expenses are approximately $4,600 per month. The lease expires on April 30, 2014. On February 1, 2009, we entered into a sublease for that office space with a sublessee, of which one of Gran Tierra’s directors is a shareholder and director of the sublessee. At the time of the transaction, another of Gran Tierra’s then directors, which director resigned as a Gran Tierra director in August 2010, was a shareholder, director and officer of the sublessee. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $7,900 per month plus approximately $4,600 for operating and other expenses. The terms of the sublease were consistent with market conditions in the Calgary real estate market.

Outlook

Business Environment

Our revenues have been impacted by the continuing fluctuations in crude oil prices. Crude oil prices are volatile and unpredictable and are influenced by concerns about financial markets and the impact of the downturn in the worldwide economy on oil demand growth. However, based on projected production, prices, costs and our current liquidity position, we believe that our current operations and capital expenditure program can be maintained from cash flow from existing operations and cash on hand, barring unforeseen events or a severe downturn in oil and gas prices. Should our operating cash flow decline, we would examine measures such as reducing our capital expenditure program, issuance of debt, disposition of assets, or issuance of equity. The current global fiscal uncertainty is having an impact on world markets, and the company is unable to determine the impact, if any, this may have on oil prices and demand.

Our future growth may depend on our ability to raise additional funds through equity and debt markets. Should we be required to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing stockholders, and this dilution would be exacerbated by a decline in our stock price. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets.

2010 Work Program and Capital Expenditure Program

Gran Tierra’s 2010 work program is intended to create value in our existing assets by growing our reserves and production from drilling financed by cash flow, while retaining financial flexibility with a strong cash position and no debt, so that we can be positioned to undertake further development opportunities from exploration success or to pursue acquisition opportunities. However, actual capital expenditures may vary significantly from our budgeted 2010 work program if unexpected events or circumstances occur, such as material delays in permitting, higher value add new opportunities present themselves, or anticipated opportunities do not come to fruition, which may therefore either increase or decrease the amount of capital expenditures we incur in 2010.

Excluding potential exploration success, we currently expect average annual production in 2010 to range between 14,000-16,000 BOPD net after royalty.

We expect that our committed and discretionary 2010 capital program can be funded from cash flow from operations and cash on hand.

Outlook – Colombia

Gran Tierra is the largest exploration landholder in the Putumayo Basin of southern Colombia. We have a working interest in sixteen blocks of land in Colombia, fifteen operated by Gran Tierra, encompassing approximately 2.6 million gross acres, or 2.3 million net acres, including three new blocks recently awarded in the 2010 Colombia Bid Round which are pending final contract approval by the ANH.

New infrastructure construction planned for the Costayaco field includes crude gathering lines, water lines, upgrading a pumping station, power generation and connections, camp and storage batteries. A water handling, processing, and injection facility for Costayaco has just been completed and is being commissioned. Two additional Costayaco development wells are planned (Costayaco -12 is expected to be completed by the end of 2010, and Costayaco -13 is planned to spud late in the fourth quarter of 2010, but will likely be completed early in the first quarter of 2011). The fourth delineation well in the Moqueta field (Chaza block) is planned for the fourth quarter of 2010 with additional delineation drilling to be evaluated in 2011 along with infrastructure development in the first quarter of 2011. Two exploration wells are planned for the fourth quarter of 2010, Taruka-1 in the Piedemonte Sur block and Pacayaco-1 in the Chaza block.

Outlook – Argentina

Gran Tierra is the largest exploration landholder in the Noroeste Basin of northern Argentina. We have a working interest in seven blocks of land, six operated by Gran Tierra, encompassing approximately 1.6 million gross acres, or 1.3 million net acres. During the third and fourth quarters of 2010 preparations for a re-entry and sidetrack of the Valle Morado VM.x-1001 gas well commenced, with testing to follow into 2011. Existing pipeline and gas processing plant capacity is capable of handling up to 35 million cubic feet per day following refurbishment. Gran Tierra has received confirmation from the Secretary of Energy that Valle Morado qualifies for the “Gas Plus Program”. This allows Gran Tierra to negotiate higher gas prices than would have been possible without the Gas Plus qualification. Recent gas contracts signed by other gas producers have resulted in gas prices in excess of $4.00 per million British thermal units. A seismic acquisition program of approximately 200km2 of 3D seismic is planned for the Santa Victoria block.

Outlook – Peru

Gran Tierra began acquiring approximately 260km of 2D seismic data in the third quarter of 2010 on Block 128. The seismic acquisition crew has now moved to Block 122 to acquire approximately 290km of 2D seismic data. Up to four stratigraphic test wells will be drilled on these Blocks commencing late in the fourth quarter of 2010 and continuing into 2011. Exploration drilling is expected to commence mid December 2010 with the Kanatari-1 well in Block 128, followed by Pichico-1 in Block 122.

Outlook – Brazil

Gran Tierra has a 70% working interest in four blocks in the on-shore Reconcavo Basin (Blocks REC-T-129, 142, 155 and 224). This recent transaction is subject to Gran Tierra Energy obtaining the customary regulatory approval from ANP. During the fourth quarter of 2010 approximately 130 km2 of 3D seismic data will be acquired over Blocks 129, 142, and 155. Exploration and development drilling is expected to commence in the second quarter of 2011.

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.

The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regards to estimates used. We believe that the assumptions, judgments and estimates involved in the accounting for oil and gas accounting and reserves determination, establishment of fair values of assets and liabilities acquired as part of acquisitions, impairment, asset retirement obligations, goodwill impairment, deferred income taxes, share-based payment arrangements, and warrants have the greatest potential impact on our consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting estimates. Our critical accounting policies and significant judgments and estimates related to those policies are discussed below.

Actual results could differ from these estimates, however, historically, our assumptions, judgments and estimates relative to our critical accounting estimates have not differed materially from actual results.

On a regular basis we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors. Our critical accounting estimates are disclosed in Item 7 of our 2009 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 26, 2010, and have not changed materially since the filing of that document.

ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our principal market risk relates to oil prices. Essentially 100% of our revenues are from oil sales at prices which are defined by contract relative to WTI and adjusted for transportation and quality, for each month. In Argentina, there is an additional withholding tax applicable on all oil exports, since November 2007. The price for the local market is negotiated within each refinery.

In accordance with the terms of the credit facility with Standard Bank Plc, which we entered into on February 28, 2007, and which expired February 22, 2010, we had entered into a costless collar financial derivative contract for crude oil based on WTI price. At December 31, 2009, this costless collar represented a liability of $44,000. As a result of the expiration of our credit facility, this costless collar has terminated.

We consider our exposure to interest rate risk to be immaterial as we hold only cash and cash equivalents. Interest rate exposures relate entirely to our investment portfolio, as we do not have short term or long term debt. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates, or government securities of the United States or Canadian federal governments such as Guaranteed Investment Certificates or Treasury Bills. We do not hold any of these investments for trading purposes. We do not hold equity investments.

Foreign currency risk is a factor for our company but is substantially mitigated by the nature of expenditures and revenues in the countries where we operate. We have not engaged in any formal hedging activity with regard to foreign currency risk. Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. price of WTI oil. The majority of our capital expenditures in Colombia are in U.S. dollars and the majority of local office costs are in local currency. Currently we receive 100% of our revenue in Colombia in U.S. dollars and may consider hedging in the future. 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 expenditures within Argentina are generally Argentine pesos. We have made four acquisitions since our inauguration. The majority of our acquisition expenditures have been paid in U.S. dollars.

Additionally, foreign exchange gains/losses result from the fluctuation of the U.S. dollar to the Colombian peso due to our deferred tax liability, a monetary liability, which is mainly denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain/loss may result on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $116,000 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). 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, 2010 to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2010, there was no change in Gran Tierra’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Gran Tierra’s internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Ecopetrol and Gran Tierra Colombia, the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the procedure for allocation of oil produced and sold during the long term test of the Guayuyaco-1 and Guayuyaco-2 wells. This matter was reported in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission on February 26, 2010.

ITEM 1A. RISK FACTORS

The risks relating to our business and industry, as set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, filed with the Securities and Exchange Commission on February 26, 2010, are set forth below and are substantially unchanged at September 30, 2010.

Risks Related to Our Business

Our Lack of Diversification Will Increase the Risk of an Investment in Our Common Stock.

Our business focuses on the oil and gas industry in a limited number of properties in Colombia, Argentina, Peru, and Brazil. Most of our production in Colombia and Argentina is limited to one basin per country. As a result, we lack diversification, in terms of both the nature and geographic scope of our business. Accordingly, factors affecting our industry or the regions in which we operate, including the geographic remoteness of our operations and weather conditions, will likely impact us more acutely than if our business was more diversified.

We May Encounter Difficulties Storing and Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses.

To sell the oil and natural gas that we are able to produce, we have to make arrangements for storage and distribution to the market. We rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. In certain areas, we may be required to rely on only one gathering system, trucking company or pipeline, and, if so, our ability to market our production would be subject to their reliability and operations. These factors may affect our ability to explore and develop properties and to store and transport our oil and gas production, and may increase our expenses.

Furthermore, future instability in one or more of the countries in which we will operate, weather conditions or natural disasters, actions by companies doing business in those countries, labor disputes or actions taken by the international community may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

The majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol and sales of oil could be disrupted by damage to this pipeline. Once delivered to Ecopetrol, all of our current oil production in Colombia is transported by an export pipeline which provides the only access to markets for our oil. Problems on these pipelines can cause interruptions to our producing activities if they are for a long enough duration that our storage facilities become full. For example, we experienced disruptions in transportation on this pipeline in March and April of 2008, again in each of June, July and August of 2009, and again in June, August, and as recently as September 2010, as a result of sabotage by guerrillas. In addition, there is competition for space in these pipelines, and additional discoveries in our area of operations by other companies could decrease the pipeline capacity available to us. Trucking is an alternative to transportation by pipeline, however it is generally more expensive and carries higher safety risks for the company and the public.

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

Guerrilla Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned About Safeguarding Our Operations and Personnel in Colombia.

A 40-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups - both funded by the drug trade - continues in Colombia. Insurgents attack civilians and sabotage property and violent guerilla activity has been escalating in many parts of the country raising additional security concerns.

We operate principally in the Putumayo basin in Colombia, and have properties in other basins, including the Catatumbo, Llanos, Middle Magdalena and Lower Magdalena basins. The Putumayo and Catatumbo regions have been prone to such guerilla activity in the past and the attacks appear to be escalating. In 1989, our predecessor company’s facilities in one field were attacked by guerillas and operations were briefly disrupted. Pipelines have also been targets, including the Ecopetrol - operated Trans Andean export pipeline which transports oil from the Putumayo region. In March and April of 2008, again in each of June, July, August and October of 2009, and again in June, August, and September 2010, sections of the Trans Andean pipeline were sabotaged by guerillas, which temporarily reduced our deliveries to Ecopetrol during the affected periods.

Continuing attempts to reduce or prevent guerilla activity may not be successful and guerilla activity may disrupt our operations in the future. There can also be no assurance that we can maintain the safety of our operations and personnel in Colombia or that this violence will not affect our operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to us.

Our Business May Suffer If We Do Not Attract and Retain Talented Personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our executive team and other personnel in conducting the business of Gran Tierra. The loss of any of these individuals or our inability to attract suitably qualified individuals to replace any of them could materially adversely impact our business. We may also experience difficulties in certain jurisdictions in our efforts to obtain suitably qualified staff and retain staff that are willing to work in that jurisdiction. We do not currently carry life insurance for our key employees.

Our success depends on the ability of our management and employees to interpret market and geological data successfully and to interpret and respond to economic, market and other business conditions in order to locate and adopt appropriate investment opportunities, monitor such investments and ultimately, if required, successfully divest such investments. Further, our key personnel may not continue their association or employment with Gran Tierra and we may not be able to find replacement personnel with comparable skills. If we are unable to attract and retain key personnel, our business may be adversely affected.

Our Oil Sales Will Depend on a Relatively Small Group of Customers, Which Could Adversely Affect Our Financial Results.

Oil sales in Colombia are made mainly to Ecopetrol. While oil prices in Colombia are related to international market prices, lack of competition and reliance on a limited number of customers for sales of oil may diminish prices and depress our financial results.

The entire Argentine domestic refining market is small and export opportunities are limited by available infrastructure. As a result, our oil sales in Argentina will depend on a relatively small group of customers, and currently, on just one customer. The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results. Currently all operators in Argentina are operating without sales contracts. We cannot provide any certainty as to when the situation will be resolved or what the final outcome will be.

Strategic Relationships Upon Which We May Rely are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.

Our ability to successfully bid on and acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements will depend on developing and maintaining effective working relationships with industry participants and on our ability to select and evaluate suitable partners and to consummate transactions in a highly competitive environment. These relationships 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 choose the wrong partner or 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 take to fulfill our obligations to these partners or maintain our relationships. If we fail to make the cash calls required by our joint venture partners in the joint ventures we do not operate, we may be required to forfeit our interests in these joint ventures. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

In addition, in cases where we are the operator, our partners may not be able to fulfill their obligations, which would require us to either take on their obligations in addition to our own, or possibly forfeit our rights to the area involved in the joint venture. In addition, despite our partner’s failure to fulfill its obligations, if we elect to terminate such relationship, we may be involved in litigation with such partners or may be required to pay amounts in settlement to avoid litigation despite such partner’s failure to perform. Alternatively, our partners may be able to fulfill their obligations, but will not agree with our proposals as operator of the property. In this case there could be disagreements between joint venture partners that could be costly in terms of dollars, time, deterioration of the partner relationship, and/or our reputation as a reputable operator. These joint venture partners may not comply with their responsibilities or may engage in conduct that could result in liability to the Company.

In cases where we are not the operator of the joint venture, the success of the projects held under these joint ventures is substantially dependent on our joint venture partners. The operator is responsible for day-to-day operations, safety, environmental compliance and relationships with government and vendors.

We have various work obligations on our blocks that must be fulfilled or we could face penalties, or lose our rights to those blocks if we do not fulfill our work obligations. Failure to fulfill obligations in one block can also have implications on the ability to operate other blocks in the country ranging from delays in government process and procedure to loss of rights in other blocks or in the country as a whole. Failure to meet obligations in one particular country may also have an impact on our ability to operate in others.

Our Business is Subject to Local Legal, Political and Economic Factors Which are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably.

We operate our business in Colombia, Argentina, Peru, and Brazil, and may eventually expand to other countries in the world. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, social unrest, strikes by local or national labor groups, interference with private contract rights (such as privatization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. For example, starting on November 21, 2008, we were forced to reduce production in Colombia on a gradual basis, culminating on December 11, 2008 when we suspended all production from the Santana, Guayuyaco and Chaza blocks in the Putumayo Basin. This temporary suspension of production operations was the result of a declaration of a state of emergency and force majeure by Ecopetrol due to a general strike in the region. In January 2009, the situation was resolved and we were able to resume production and sales shipments. In 2010, there has been an increased presence of illegitimate unionization activities in the Putumayo Basin by the Sintrapetorputumayo which has disrupted the Company’s operations from time to time and may do so in the future.

South America has a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. Any changes in oil and gas or investment regulations and policies or a shift in political attitudes in Argentina, Colombia, Peru or Brazil or other countries in which we intend to operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

For instance, changes in laws in the jurisdiction in which we operate or expand into with the effect of favoring local enterprises, and changes in political views regarding the exploitation of natural resources and economic pressures, may make it more difficult for us to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations. In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. Property right transfers, joint ventures, licenses, license applications or other legal arrangements pursuant to which we operate may be adversely affected by the actions of government authorities and the effectiveness of and enforcement of our rights under such arrangements in these jurisdictions may be impaired.

Foreign Currency Exchange Rate Fluctuations May Affect Our Financial Results.

We expect to sell our oil and natural gas production under agreements that will be denominated in United States dollars and foreign currencies. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. Our production is primarily invoiced in United States dollars, but payment is also made in Argentine and Colombian pesos, at the then-current exchange rate. As a result, we are exposed to translation risk when local currency financial statements are translated to United States dollars, our company’s functional currency. Since we began operating in Argentina (September 1, 2005), the rate of exchange between the Argentine peso and US dollar has varied between 3.05 pesos to one US dollar to 3.96 pesos to the US dollar, a fluctuation of approximately 30%. Exchange rates between the Colombian peso and US dollar have varied between 2,632 pesos to one US dollar to 1,648 pesos to one US dollar since September 1, 2005, a fluctuation of approximately 60%.

In addition, a foreign exchange loss of $33.7 million, of which $27.1 million is an unrealized non-cash foreign exchange loss, was recorded in the first nine months of 2010 primarily due to the translation of a deferred tax liability recorded on the purchase of Solana. The deferred tax liability is denominated in Colombian pesos and the devaluation of 12% in the US dollar against the Colombian Peso in the first nine months of 2010 resulted in the foreign exchange loss.

Exchange Controls and New Taxes Could Materially Affect our Ability to Fund Our Operations and Realize Profits from Our Foreign Operations.

Foreign operations may require funding if their cash requirements exceed operating cash flow. To the extent that funding is required, there may be exchange controls limiting such funding or adverse tax consequences associated with such funding. In addition, taxes and exchange controls may affect the dividends that we receive from foreign subsidiaries.

Exchange controls may prevent us from transferring funds abroad. For example, the Argentine government has imposed a number of monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by the Argentine Central Bank. The Central Bank may require prior authorization and may or may not grant such authorization for our Argentine subsidiaries to make dividend payments to us and there may be a tax imposed with respect to the expatriation of the proceeds from our foreign subsidiaries.

Competition in Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair Our Business.

The oil and gas industry is highly competitive. Other oil and gas companies will compete with us by bidding for exploration and production licenses and other properties and services we will need to operate our business in the countries in which we expect to operate. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger, foreign owned companies, which, in particular, may have access to greater resources than us, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. In the event that we do not succeed in negotiating additional property acquisitions, our future prospects will likely be substantially limited, and our financial condition and results of operations may deteriorate.

Maintaining Good Community Relationships and Being a Good Corporate Citizen may be Costly and Difficult to Manage.

Our operations have a significant effect on the areas in which we operate. To enjoy the confidence of local populations and the local governments, we must invest in the communities where were operate. In many cases, these communities are impoverished and lack many resources taken for granted in North America. The opportunities for investment are large, many and varied; however, we must be careful to invest carefully in projects that will truly benefit these areas. Improper management of these investments and relationships could lead to a delay in operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business.

Our Operations Involve Substantial Costs and are Subject to Certain Risks Because the Oil and Gas Industries in the Countries in Which We Operate are Less Developed.

The oil and gas industry in South America is not as efficient or developed as the oil and gas industry in North America. As a result, our exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. We expect that such factors will subject our international operations to economic and operating risks that may not be experienced in North American operations.

Negative Political and Regulatory Developments in Argentina May Negatively Affect our Operations.

The crude oil and natural gas industry in Argentina is subject to extensive regulation including land tenure, exploration, development, production, refining, transportation, and marketing, imposed by legislation enacted by various levels of government and, with respect to pricing and taxation of crude oil and natural gas, by agreements among the federal and provincial governments, all of which are subject to change and could have a material impact on our business in Argentina. The Federal Government of Argentina has implemented controls for domestic fuel prices and has placed a tax on crude oil and natural gas exports.

Any future regulations that limit the amount of oil and gas that we could sell or any regulations that limit price increases in Argentina and elsewhere could severely limit the amount of our revenue and affect our results of operations.

Currently most oil and gas producers in Argentina are operating without sales contracts. In 2008, a new withholding tax regime for exports was introduced without specific guidance as to its application. The domestic price was regulated in a similar way, so that both exported and domestically sold products were priced the same. Producers and refiners of oil in Argentina were unable to determine an agreed sales price for oil deliveries to refineries. In our case, 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 negotiating sales on a spot price basis with one, Refiner S.A., and the price is negotiated on a month by month basis. From January to May 2009, we delivered two truckloads per day to Polipetrol in Mendoza province, and that price was negotiated weekly. We stopped delivering to Polipetrol in May 2009, due to possible financial problems at the refinery. The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced and capital investment in oilfields has declined, and so they are lobbying to change the situation. We are working with other oil and gas producers in the area, as well as Refiner S.A., to lobby the federal government for change. The government introduced the Petro Plus and Gas Plus programs in 2009, which grant higher prices to producers that sell production from new reserves. This is a positive step forward that will hopefully lead to further opening of price regulation in Argentina.

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

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

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

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

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

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

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with ANH and Ecopetrol and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. The United States may impose sanctions on Colombia in the future, and we cannot predict the effect in Colombia that these sanctions might cause.

We May Be Unable to Obtain Additional Capital That We Will Require to Implement Our Business Plan, Which Could Restrict Our Ability to Grow.

We expect that our existing cash resources will be sufficient to fund our currently planned activities. We may require additional capital to expand our exploration and development programs to additional properties. We may be unable to obtain additional capital required.

When we require additional capital we plan to pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. 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 addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which will adversely impact our financial results.

Our ability to obtain needed financing may be impaired by factors such as the capital markets (both generally and in the oil and gas industry in particular), the location of our oil and natural gas properties in South America, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us), and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. If the amount of capital we are able to raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to cease our operations.

We May Not Be Able To Effectively Manage Our Growth, Which May Harm Our Profitability.

Our strategy envisions continually expanding our business, both organically and through acquisition of other properties and companies. If we fail to effectively manage our growth or integrate successfully our acquisitions, 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 or acquired employees. We may not be able to:

expand our systems effectively or efficiently or in a timely manner;

allocate our human resources optimally;

identify and hire qualified employees or retain valued employees; or

incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth and our operations our financial results could be adversely affected by inefficiencies, which could diminish our profitability.

Risks Related to Our Industry

Unless We are Able to Replace Our Reserves, and Develop Oil and Gas Reserves on an Economically Viable Basis, Our Reserves, Production and Cash Flows May Decline as a Result.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. We may not be able to find, develop or acquire additional reserves at acceptable costs.

To the extent that we succeed in discovering oil and/or natural gas, reserves may not be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our company’s viability depends on our ability to find or acquire, develop and commercially produce additional oil and gas reserves. Without the addition of reserves through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we may not be able to do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We are Required to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain These Licenses or to Obtain Them on a Timely Basis 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 on a timely basis or at all. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations.

Our Exploration for Oil and Natural Gas Is Risky and May Not Be Commercially Successful, Impairing Our Ability to Generate Revenues from Our Operations.

Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our exploration expenditures may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

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

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

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

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

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.

Drilling New Wells and Producing Oil and Natural Gas from Existing Facilities Could Result in New Liabilities, Which Could Endanger Our Interests in Our Properties and Assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. Earthquakes or weather related phenomena such as heavy rain, landslides, storms and hurricanes can also cause problems in drilling new wells. There are also risks in producing oil and natural gas from existing facilities. For example, the Valle Morado-1001 re-entry operations started in the third quarter of 2010, with integrity testing and remediation operations required for the sidetrack operations. Due to operational difficulties the initial side-track attempt was not successful. Currently the operation has been placed on standby pending the arrival of additional side-track equipment, before recommencing the side-track operation in fourth quarter, 2010. Also for example, on February 7, 2009 we experienced an incident at our Juanambu 1 well, involving a fire in a generator, resulting in total damage to equipment estimated at $500,000, and production in the amount of approximately $125,000 being deferred due to shutting down production facilities while dealing with the incident. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. Incidents such as these can lead to serious injury, property damage and even loss of life. We generally obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

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

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

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

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

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

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for WTI in 2006 was $66 per barrel, in 2007 it was $72 per barrel, in 2008 it was $100 per barrel, and in 2009 it was $62 per barrel. However, the average price for the nine months ended September 30, 2010 was $78, demonstrating the inherent volatility in the market. We expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our oil and gas reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differences. These differentials can change over time and have a detrimental impact on realized prices. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

In addition, oil and natural gas prices in Argentina are effectively regulated and during 2009 and 2010 were substantially lower than those received in North America. Oil prices in Colombia are related to international market prices, but adjustments that are defined by contract with Ecopetrol, the purchaser of most of the oil that we produce in Colombia, may cause realized prices to be lower than those received in North America.

Penalties We May Incur Could Impair Our Business.

Our exploration, development, production and marketing operations are regulated extensively under foreign, federal, state and local laws and regulations. Under these laws and regulations, we could be held liable for personal injuries, property damage, site clean-up and restoration obligations or costs and other damages and liabilities. We may also be required to take corrective actions, such as installing additional safety or environmental equipment, which could require us to make significant capital expenditures. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. We could be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result of these laws and regulations, our future business prospects could deteriorate and our profitability could be impaired by costs of compliance, remedy or indemnification of our employees, reducing our profitability.

Policies, Procedures and Systems to Safeguard Employee Health, Safety and Security May Not be Adequate.

Oil and natural gas exploration and production is dangerous. Detailed and specialized policies, procedures and systems are required to safeguard employee health, safety and security. We have undertaken to implement best practices for employee health, safety and security; however, if these policies, procedures and systems are not adequate, or employees do not receive adequate training, the consequences can be severe including serious injury or loss of life, which could impair our operations and cause us to incur significant legal liability.

Environmental Risks May Adversely Affect Our Business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and federal, provincial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to foreign governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Our Insurance May Be Inadequate to Cover Liabilities We May Incur.

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we have insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Challenges to Our Properties May Impact Our Financial Condition.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interest in and to the properties to which the title defects relate.

Furthermore, applicable governments may revoke or unfavorably alter the conditions of exploration and development authorizations that we procure, or third parties may challenge any exploration and development authorizations we procure. Such rights or additional rights we apply for may not be granted or renewed on terms satisfactory to us.

If our property rights are reduced, whether by governmental action or third party challenges, our ability to conduct our exploration, development and production may be impaired.

We Will Rely on Technology to Conduct Our Business and Our Technology Could Become Ineffective Or Obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration and development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

Risks Related to Our Common Stock

The Market Price of Our Common Stock May Be Highly Volatile and Subject to Wide Fluctuations.

The market price of our common stock may be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including but not limited to:

dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

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

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

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

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

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

In addition, the market price of our common stock could be subject to wide fluctuations in response to various factors, which could include the following, among others:

·	quarterly variations in our revenues and operating expenses;

·	changes in the valuation of similarly situated companies, both in our industry and in other industries;

·	changes in analysts’ estimates affecting our company, our competitors and/or our industry;

·	changes in the accounting methods used in or otherwise affecting our industry;

·	additions and departures of key personnel;

·	announcements of technological innovations or new products available to the oil and natural gas industry;

·	announcements by relevant governments pertaining to incentives for alternative energy development programs;

·	fluctuations in interest rates, exchange rates and the availability of capital in the capital markets; and

·	significant sales of our common stock, including sales by future investors in future offerings we expect to make to raise additional capital.

These and other factors are largely beyond our control, and the impact of these risks, singularly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our results of operations and financial condition.

Our Operating Results May Fluctuate Significantly, and These Fluctuations May Cause Our Stock Price to Decline.

Our operating results will likely vary in the future primarily from fluctuations in our revenues and operating expenses, including the ability to produce the oil and natural gas reserves that we are able to develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.

We Do Not Expect to Pay Dividends In the Foreseeable Future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On seventeen separate dates beginning on July 1, 2010 and ending on September 30, 2010, we sold an aggregate of 1,678,956 shares of our common stock for an aggregate purchase price of $2,098,515. These shares were issued to thirty-three (33) 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 21, 2010, we issued 79,365 shares of our common stock to one 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 6. EXHIBITS

See Index to Exhibits at the end of this Report, which is incorporated by reference here. The Exhibits listed in the accompanying Index to Exhibits are filed as part of this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

GRAN TIERRA ENERGY INC.

Date: November 5, 2010	/s/ Dana Coffield
	By: Dana Coffield
Its: Chief Executive Officer (duly authorized officer)

Date: November 5, 2010	/s/ Martin Eden
	By: Martin Eden
Its: Chief Financial Officer (principal financial officer)

EXHIBIT INDEX

Exhibit No.	Description	Reference

3.1	Amended and Restated Articles of Incorporation.	Incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A (Reg. No. 001-34018), filed with the SEC on January 6, 2010.

3.2	Amended and Restated Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2008 (File No. 000-52594).
4.1	Reference is made to Exhibits 3.1 to 3.2.

4.2	Form of Warrant issued to investors in connection with the private offering in 2005.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 19, 2005 (File No. 333-111656).

4.3	Form of Warrant issued to institutional and retail investors in connection with the private offering in June 2006.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 21, 2006 (File No. 333-111656).

4.4	Details of the Goldstrike Special Voting Share.	Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).

4.5	Goldstrike Exchangeable Share Provisions.	Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the Securities and Exchange on April 21, 2006 (File No. 333-111656).

10.1	Credit Agreement, dated as of July 30, 2010, among Solana Resources Limited, Gran Tierra Energy Inc., the Lenders party thereto, and BNP Paribas.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 5, 2010 (File No. 333-111656).

10.2	First Amendment to Credit Agreement, dated as of August 30, 2010, among Solana Resources Limited, Gran Tierra Energy Inc., BNP Paribas and Other Lenders	Filed herewith.

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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

XBRL information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.