GTE 10-Q Quarterly Report June 30, 2011

GRAN TIERRA ENERGY INC.

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10-Q 1 form10q.htm GRAN TIERRA ENERGY INC 10-Q 6-30-2011 form10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED June 30, 2011

¨	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 11 th 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 ¨

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

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

On August 3, 2011, the following numbers of shares of the registrant’s capital stock were outstanding: 261,011,061 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 8,881,718 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	21

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41

ITEM 4.	CONTROLS AND PROCEDURES	41

PART II - OTHER INFORMATION

ITEM 1A.	RISK FACTORS	42

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52

ITEM 5.	OTHER INFORMATION	52

ITEM 6.	EXHIBITS	52

SIGNATURES		52

EXHIBIT INDEX		53

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1 - FINANCIAL STATEMENTS

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations and Retained Earnings (Unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010

REVENUE AND OTHER INCOME
Oil and natural gas sales	$	161,664		$	83,717		$	283,960		$	176,649
Interest		456			397			679			575
		162,120			84,114			284,639			177,224
EXPENSES
Operating		23,160			9,529			39,556			19,714
Depletion, depreciation, accretion, and impairment (Note 5)		46,965			31,641			110,322			71,984
General and administrative		16,410			9,594			30,048			16,784
Equity tax (Note 8)		221			-			8,271			-
Financial instruments gain (Note 6)		(1,292	)		-			(1,522	)		(44	)
Loss (gain) on acquisition (Note 3)		2,601			-			(21,699	)		-
Foreign exchange loss		14,495			3,126			19,694			17,420
		102,560			53,890			184,670			125,858

INCOME BEFORE INCOME TAXES		59,560			30,224			99,969			51,366
Income tax expense (Note 8)		(27,993	)		(12,853	)		(54,689	)		(24,035	)
NET INCOME AND COMPREHENSIVE INCOME		31,567			17,371			45,280			27,331
RETAINED EARNINGS, BEGINNING OF PERIOD		71,810			30,885			58,097			20,925
RETAINED EARNINGS, END OF PERIOD	$	103,377		$	48,256		$	103,377		$	48,256

NET INCOME PER SHARE — BASIC	$	0.11		$	0.07		$	0.17		$	0.11
NET INCOME PER SHARE — DILUTED	$	0.11		$	0.07		$	0.16		$	0.10
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)		277,297,728			254,344,474			269,159,453			251,234,950
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)		284,451,536			263,853,024			277,530,126			260,922,669

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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

	June 30,		December 31,
	2011		2010

ASSETS
Current Assets
Cash and cash equivalents	$	211,355	$	355,428
Restricted cash (Note 12)		11,465		250
Accounts receivable		156,350		43,035
Inventory (Note 2)		7,109		5,669
Taxes receivable		20,274		6,974
Prepaids		2,486		1,940
Deferred tax assets (Note 8)		2,643		4,852

Total Current Assets		411,682		418,148

Oil and Gas Properties (using the full cost method of accounting)
Proved		567,422		442,404
Unproved		434,254		278,753

Total Oil and Gas Properties		1,001,676		721,157

Other capital assets		7,379		5,867

Total Property, Plant and Equipment (Note 5)		1,009,055		727,024

Other Long Term Assets
Restricted cash (Note 12)		1,359		1,190
Deferred tax assets (Note 8)		12,082		-
Other long term assets		297		311
Goodwill		102,581		102,581

Total Other Long Term Assets		116,319		104,082

Total Assets	$	1,537,056	$	1,249,254

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable (Note 9)	$	49,727	$	76,023
Accrued liabilities (Note 9)		74,300		32,120
Bank debt (Notes 12 and 14)		31,250		-
Taxes payable		40,723		43,832
Asset retirement obligations (Note 7)		322		338

Total Current Liabilities		196,322		152,313

Long Term Liabilities
Deferred tax liabilities (Note 8)		231,558		204,570
Equity tax payable (Note 8)		10,293		-
Asset retirement obligations (Note 7)		10,468		4,469
Other long term liabilities		5,811		1,036

Total Long Term Liabilities		258,130		210,075

Commitments and Contingencies (Note 10)
Subsequent Event (Note 14)
Shareholders’ Equity
Common shares (Note 6)		5,846		4,797
(260,977,461 and 240,440,830 common shares and 16,726,430 and 17,681,123 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2011 and December 31, 2010, respectively)
Additional paid in capital		971,601		821,781
Warrants (Note 6)		1,780		2,191
Retained earnings		103,377		58,097

Total Shareholders’ Equity		1,082,604		886,866

Total Liabilities and Shareholders’ Equity	$	1,537,056	$	1,249,254

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended June 30,
	2011			2010

Operating Activities
Net income	$	45,280		$	27,331
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depletion, depreciation, accretion, and impairment		110,322			71,984
Deferred taxes (Note 8)		(5,406	)		(18,031	)
Stock-based compensation (Note 6)		5,945			3,360
Unrealized gain on financial instruments (Note 11)		(1,354	)		(44	)
Unrealized foreign exchange loss		16,102			13,997
Settlement of asset retirement obligations (Note 7)		(309	)		-
Equity taxes		6,251			-
Gain on acquisition (Note 3)		(21,699	)		-
Net changes in non-cash working capital
Accounts receivable		(100,955	)		(35,435	)
Inventory		(213	)		(487	)
Prepaids		(211	)		(377	)
Accounts payable and accrued liabilities		(2,521	)		(14,216	)
Taxes receivable and payable		(18,120	)		4,887

Net cash provided by operating activities		33,112			52,969

Investing Activities
Restricted cash		(8,139	)		661
Additions to property, plant and equipment		(179,155	)		(50,914	)
Proceeds from disposition of oil and gas property		-			1,200
Cash acquired on acquisition (Note 3)		7,747			-
Proceeds on sale of asset backed commercial paper (Note 3)		22,679			-
Long term assets and liabilities		13			20

Net cash used in investing activities		(156,855	)		(49,033	)

Financing Activities
Settlement of bank debt (Notes 3)		(22,853	)		-
Proceeds from issuance of common shares		2,523			18,504

Net cash (used in) provided by financing activities		(20,330	)		18,504

Net increase (decrease) in cash and cash equivalents		(144,073	)		22,440
Cash and cash equivalents, beginning of period		355,428			270,786

Cash and cash equivalents, end of period	$	211,355		$	293,226

Cash	$	135,142		$	194,465
Term deposits		76,213			98,761
Cash and cash equivalents, end of period	$	211,355		$	293,226

Supplemental cash flow disclosures:
Cash paid for interest	$	1,344		$	-
Cash paid for income taxes	$	64,205		$	32,512
Non-cash investing activities:
Non-cash working capital related to property, plant and equipment	$	39,118		$	21,220

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended			Year Ended
	June 30, 2011			December 31, 2010

Share Capital
Balance, beginning of period	$	4,797		$	1,431
Issue of common shares		1,049			3,366

Balance, end of period		5,846			4,797


Additional Paid in Capital
Balance, beginning of period		821,781			766,963
Issue of common shares		142,233			19,119
Exercise of warrants (Note 6)		411			24,916
Exercise of stock options (Note 6)		928			2,300
Stock-based compensation expense (Note 6)		6,248			8,483

Balance, end of period		971,601			821,781


Warrants
Balance, beginning of period		2,191			27,107
Exercise of warrants (Note 6)		(411	)		(24,916	)

Balance, end of period		1,780			2,191

Retained Earnings
Balance, beginning of period		58,097			20,925
Net income		45,280			37,172

Balance, end of period		103,377			58,097

Total Shareholders’ Equity	$	1,082,604		$	886,866

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

1. Description of Business

Gran Tierra Energy Inc., a Nevada corporation (the “Company” or “Gran Tierra”), is a publicly traded oil and gas company engaged in acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Colombia, Argentina, Peru and Brazil.

2. Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the interim consolidated financial statements, and revenues and expenses during the reporting period. In the opinion of the Company’s management, all adjustments (all of which are normal and recurring) that have been made are necessary to fairly state the consolidated financial position of the Company as at June 30, 2011, the results of its operations for the three and six month periods ended June 30, 2011 and 2010, and its cash flows for the six month periods ended June 30, 2011 and 2010.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim condensed consolidated financial statements. Accordingly, these interim condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2010 included in the Company’s 2010 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 25, 2011. The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2010 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 condensed consolidated financial statements were issued.

Warrants

The Company issued warrants (“Replacement Warrants”) in connection with its acquisition of Petrolifera Petroleum Limited (“Petrolifera”) during March 2011 (Note 3). These warrants are derivative financial instruments and are recorded at fair value in the consolidated balance sheet as a current liability and as part of the consideration paid for the acquisition . Any changes in the fair value of these derivative instruments are recorded in net income when those changes occur. The Company determines the fair value of warrants using the Black-Scholes option pricing model. The Company does not use derivative financial instruments for speculative purposes.

Inventory

Crude oil inventories at June 30, 2011 and December 31, 2010 are $5.0 million and $3.6 million, respectively. Supplies at June 30, 2011 and December 31, 2010 are each $2.1 million.

New Accounting Pronouncements

Stock Compensation

In April 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”), "Compensation–Stock Compensation (Topic 718)." The update clarifies 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 did not materially impact the Company’s consolidated financial position, operating results or cash flows.

Business Combinations

In December 2010, the FASB issued ASU, "Business Combinations (Topic 850), Disclosures of Supplementary Pro Forma Information for Business Combinations." The update is intended to conform reporting of pro forma revenue and earnings for material business combinations included in the notes to the financial statements and expand disclosure of non-recurring adjustments that are directly attributable to the business combination. The pro forma revenue and earnings of the combined entity are presented as if the acquisition had occurred as of the beginning of the annual reporting period. If comparatives are presented, the pro forma disclosures for both periods presented should be reported as if the acquisition had occurred as of the beginning of the comparable prior annual reporting period only. This ASU is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The implementation of this update did not materially impact the Company’s disclosures.

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3. Business Combination

On March 18, 2011 (the “Acquisition Date”), Gran Tierra completed its acquisition of all the issued and outstanding common shares and warrants of Petrolifera, a Canadian corporation, pursuant to the terms and conditions of an arrangement agreement dated January 17, 2011 (the “Arrangement”). Petrolifera is a Calgary-based crude oil, natural gas and natural gas liquids exploration, development and production company active in Argentina, Colombia and Peru. The transaction contemplated by the Arrangement was effected through a court-approved plan of arrangement in Canada. The Arrangement was approved at a special meeting of Petrolifera shareholders on March 17, 2011 and by the Court of Queen's Bench of Alberta on March 18, 2011.

Under the Arrangement, Petrolifera shareholders received, for each Petrolifera share held, 0.1241 of a share of Gran Tierra common stock, and Petrolifera warrant holders received, for each Petrolifera warrant held, 0.1241 of a Replacement Warrant to purchase a share of Gran Tierra common stock at an exercise price of $9.67 Canadian (“CDN”) dollars per share. Gran Tierra Replacement Warrants are only net exercisable, and expire on August 28, 2011.

Gran Tierra acquired all the issued and outstanding Petrolifera shares and warrants through the issuance of 18,075,247 Gran Tierra common shares, par value $0.001, and 4,125,036 Replacement Warrants. Upon completion of the transaction on the Acquisition Date, Petrolifera became an indirect wholly owned subsidiary of Gran Tierra. On a diluted basis, upon the closing of the Arrangement, Petrolifera and Gran Tierra security holders owned approximately 6.6% and 93.4% of the Company, respectively, immediately following the transaction. The total consideration for the transaction was approximately $143 million.

The fair value of Gran Tierra’s common shares was determined as the closing price of the common shares of Gran Tierra as at the Acquisition Date. The fair value of the Replacement Warrants was estimated on the Acquisition Date using the Black-Scholes option pricing model with the following assumptions:

Exercise price (CDN dollars per warrant)	$	9.67
Risk-free interest rate		1.3	%
Expected life	0.45 Years
Volatility		44	%
Expected annual dividend per share	Nil
Estimated fair value per warrant (CDN dollars)	$	0.32

Gran Tierra’s Replacement Warrants issued as a result of the acquisition meet the definition of a derivative. Because the exercise price of the Replacement Warrants is denominated in Canadian dollars, which is different from Gran Tierra’s functional currency, the Replacement Warrants are not considered indexed to Gran Tierra’s common shares and the Replacement Warrants cannot be classified within equity. Therefore the Replacement Warrants, which expire in August 2011, are classified as a current liability on Gran Tierra’s condensed consolidated balance sheet.

The acquisition is accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed are recorded at their fair values as at the Acquisition Date and the results of Petrolifera have been consolidated with those of Gran Tierra from that date.

The following table shows the allocation of the consideration transferred based on the fair values of the assets and liabilities acquired:

(Thousands of U.S. Dollars)
Consideration Transferred:
Common shares issued net of share issue costs	$	141,690
Replacement warrants		1,354
	$	143,044

Allocation of Consideration Transferred (1):
Oil and gas properties
Proved	$	58,457
Unproved		161,278
Other long term assets		4,417
Net working capital (including cash acquired of $7.7 million and accounts receivable of $6.4 million)		(17,223	)
Asset retirement obligations		(4,901	)
Bank debt		(22,853	)
Other long term liabilities		(14,432	)
Gain on acquisition		(21,699	)
	$	143,044

(1) The allocation of the consideration transferred is not final and is subject to change.

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As shown above in the allocation of the consideration transferred, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra recognized a gain of $21.7 million, which is reported as “Gain on acquisition”, in the consolidated statement of operations. The gain reflects the impact on Petrolifera’s pre-acquisition market value of a lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects. Subsequent to the initial allocation of the consideration reported in the first quarter of 2011, further assessment of Petrolifera’s tax position resulted in a reduction of the gain on acquisition to $21.7 million from $24.3 million previously reported. A corresponding adjustment has been made to the net working capital deficiency assumed.

As part of the assets acquired and included in the net working capital in the allocation of the consideration transferred, the Company assigned $22.5 million in fair value to investments in notes that Petrolifera received in exchange for asset backed commercial paper (“ABCP”) with a face value of $31.3 million. On March 28, 2011, these notes were sold to an unrelated party for proceeds of $22.7 million after the associated line of credit was settled.

The associated ABCP line of credit that Gran Tierra assumed was with a Canadian Chartered Bank, to a maximum of CDN$23.2 million with an initial expiry in April 2012. Gran Tierra settled this line of credit immediately after the completion of the acquisition of Petrolifera for the face value of CDN$22.5 million in borrowings plus accrued interest.

Also upon the acquisition of Petrolifera, Gran Tierra assumed a second line of credit agreement (“Second ABCP line of credit”) with the same Canadian chartered bank to a maximum of CDN$5.0 million, which was fully drawn as at the Acquisition Date. This Second ABCP line of credit, which expired on April 8, 2011, was secured by ineligible master asset vehicles Classes 1 & 2 (“MAV IA 1 & 2”) notes with a face value of $6.6 million. Gran Tierra retained the option to settle the Second ABCP line of credit of CDN$5.0 million through delivery to the lender of the MAV IA 1 & 2 notes. Subsequent to the acquisition, Gran Tierra elected to record this second line of credit at fair value and planned at that time to settle the debt through delivery of the MAV IA 1 & 2 notes upon expiry. Accordingly, a value of $nil was recorded for the debt upon its acquisition. Gran Tierra settled such borrowings by delivery of the MAV IA 1 & 2 notes on April 8, 2011.

Gran Tierra also assumed a reserve-backed credit facility upon the Petrolifera acquisition (Note 12). The amount outstanding under this credit facility is included as part of net working capital in the allocation of consideration transferred and is reflected as a current liability in the statement of financial position as at June 30, 2011. This credit facility had an outstanding balance of $31.3 million at June 30, 2011.

The pro forma results for the three months ended June 30, 2011 and the three and six months ended June 30, 2011 and 2010 are shown below, as if the acquisition had occurred on January 1, 2010. Pro forma results are not indicative of actual results or future performance.

	Three Months Ended June 30,		Six Months Ended June 30,
(Unaudited) (Thousands of U.S. Dollars except per share amounts)	2010		2011		2010
Oil and natural gas sales and interest	$	98,130	$	293,834	$	206,012
Net income	$	19,719	$	12,457	$	31,540
Net income per share - basic	$	0.07	$	0.05	$	0.12
Net income per share - diluted	$	0.07	$	0.04	$	0.10

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The supplemental pro forma earnings of Gran Tierra for the three and six months ended June 30, 2011 were adjusted to exclude $4.4 million of acquisition costs recorded in general and administrative expense and the $21.7 million gain on acquisition recognized in the 2011 results of Gran Tierra because they are not expected to have a continuing impact on Gran Tierra’s results of operations. The consolidated statement of operations for the six months ended June 30, 2011 includes revenues of $10.9 million from Petrolifera for the period subsequent to the Acquisition Date. Net income from Petrolifera for the period since the Acquisition Date was not material.

4. Segment and Geographic Reporting

The Company’s reportable operating segments are Colombia, Argentina, Peru and Corporate, based on a geographic organization. The Company is primarily engaged in the exploration and production of oil and natural gas. In the three and six months ended June 30, 2011, Peru became a reportable geographic segment due to the significance of its loss before income taxes as compared to the consolidated results of operations. Prior year comparative geographic segment presentation has been conformed to this presentation with the Peru related results and asset information disaggregated from the Corporate segment. Brazil is included as part of the Corporate segment and is not a reportable segment because the level of activity is not significant at this time. The accounting policies of the reportable geographic segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on income 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 June 30, 2011
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Peru			Corporate			Total
Revenues	$	148,473	$	12,857		$	-		$	334		$	161,664
Interest income		158		28			134			136			456
Depreciation, depletion, accretion and impairment		39,609		5,505			1,530			321			46,965
Depreciation, depletion, accretion and impairment - per unit of production		28.49		21.45			-			-			28.45
Segment income (loss) before income taxes		73,729		(3,099	)		(2,371	)		(8,699	)		59,560
Segment capital expenditures	$	54,216	$	7,138		$	11,287		$	28,848		$	101,489

	Three Months Ended June 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Peru			Corporate			Total
Revenues	$	80,603	$	3,114		$	-		$	-		$	83,717
Interest income		142		3			-			252			397
Depreciation, depletion, and accretion		30,321		1,224			3			93			31,641
Depreciation, depletion, and accretion - per unit of production		26.33		18.71			-			-			26.00
Segment income (loss) before income taxes		37,089		(1,109	)		(242	)		(5,514	)		30,224
Segment capital expenditures	$	28,894	$	3,814		$	1,609		$	539		$	34,856

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	Six Months Ended June 30, 2011
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Peru			Corporate		Total
Revenues	$	265,777	$	17,849		$	-		$	334	$	283,960
Interest income		245		28			134			272		679
Depreciation, depletion, accretion, and impairment		69,645		6,652			33,463			562		110,322
Depreciation, depletion, accretion, and impairment - per unit of production		26.75		18.85			-			-		37.27
Segment income (loss) before income taxes		131,615		(3,529	)		(34,996	)		6,879		99,969
Segment capital expenditures (1)	$	96,480	$	18,760		$	25,574		$	29,778	$	170,592

	Six Months Ended June 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Peru			Corporate			Total
Revenues	$	170,036	$	6,613		$	-		$	-		$	176,649
Interest income		219		19			-			337			575
Depreciation, depletion, accretion, and impairment		65,327		6,491			11			155			71,984
Depreciation, depletion, accretion, and impairment - per unit of production		26.98		45.86			-			-			28.09
Segment income (loss) before income taxes		65,849		(5,753	)		(491	)		(8,239	)		51,366
Segment capital expenditures	$	46,447	$	4,474		$	2,136		$	1,303		$	54,360

	As at June 30, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Corporate		Total
Property, plant and equipment	$	781,474	$	150,258	$	32,559	$	44,764	$	1,009,055
Goodwill		102,581		-		-		-		102,581
Other assets		235,148		39,586		8,498		142,188		425,420
Total Assets	$	1,119,203	$	189,844	$	41,057	$	186,952	$	1,537,056

	As at December 31, 2010
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Corporate		Total
Property, plant and equipment	$	654,416	$	29,031	$	28,578	$	14,999	$	727,024
Goodwill		102,581		-		-		-		102,581
Other assets		155,798		15,220		18,575		230,056		419,649
Total Assets	$	912,795	$	44,251	$	47,153	$	245,055	$	1,249,254

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 2011, the Company has one significant customer for its Colombian crude oil, Ecopetrol S.A. (“Ecopetrol”). Sales to Ecopetrol accounted for 88% and 96% of the Company’s revenues in the second quarters of 2011 and 2010, respectively. Sales to Ecopetrol accounted for 89% and 96% of the Company’s revenues for the six month periods ended June 30, 2011 and 2010, respectively. In Argentina, the Company has two significant customers, Refineria del Norte S.A (“Refiner”) and Shell C.A.P.S.A. (“Shell”). Sales to Refiner accounted for 2% and 4% of the Company’s revenues for the three month periods ended June 30, 2011 and 2010, respectively and 3% and 4% of the Company’s revenues for the six month periods ended June 30, 2011 and 2010, respectively. Sales to Shell accounted for 7% and 4% of the Company’s revenues for the three and six month periods ended June 30, 2011, respectively.

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5. Property, Plant and Equipment

	As at June 30, 2011							As at December 31, 2010
(Thousands of U.S. Dollars)	Cost		Accumulated DD&A			Net book value		Cost		Accumulated DD&A			Net book value
Oil and Gas Properties
Proved	$	1,012,173	$	(444,751	)	$	567,422	$	777,262	$	(334,858	)	$	442,404
Unproved		434,254		-			434,254		278,753		-			278,753
		1,446,427		(444,751	)		1,001,676		1,056,015		(334,858	)		721,157
Furniture and fixtures and leasehold improvements		5,883		(3,185	)		2,698		5,233		(2,831	)		2,402
Computer equipment		6,799		(2,613	)		4,186		5,521		(2,358	)		3,163
Automobiles		1,029		(534	)		495		779		(477	)		302
Total Property, Plant and Equipment	$	1,460,138	$	(451,083	)	$	1,009,055	$	1,067,548	$	(340,524	)	$	727,024

On August 26, 2010, the Company entered into an agreement to acquire a 70% participating interest in four blocks in Brazil. With the exception of one block which has a producing well, the remaining blocks are unproved properties. The agreement was effective September 1, 2010, subject to regulatory approvals, and the transaction was completed on June 15, 2011. Purchase consideration of $40.1 million recorded as corporate segment capital expenditures in 2011 and 2010, included cash payments of $22.6 million and an obligation to fund certain exploratory activities, including the drilling of two exploratory wells in the acquired areas. The 70% share of all benefits and costs with respect to the period between the effective date and the completion of the transaction were an adjustment to the consideration paid for the four blocks.

Depreciation, depletion, accretion and impairment (“DD&A”) for the six months ended June 30, 2011 includes a ceiling test impairment loss of $33.4 million in Gran Tierra’s Peru cost center. This impairment loss was a result of the inclusion of dry well costs and seismic costs associated with the asset base of the Peru cost center for ceiling test determination purposes. For the six months ended June 30, 2010, a $3.7 million ceiling test impairment loss was included in the Company’s Argentina cost center. This impairment loss was a result of a redetermination of the income tax effect on the present value of future cash inflows used to determine the Argentina ceiling for that country’s ceiling test.

During the six months ended June 30, 2011, the Company capitalized $3.7 million (year ended December 31, 2010 - $4.1 million) of general and administrative expenses related to the Colombian cost center, including $0.2 million (year ended December 31, 2010 - $0.3 million) of stock-based compensation expense, and $1.0 million (year ended December 31, 2010 - $1.2 million) of general and administrative expenses in the Argentina full cost center, including $0.1 million (year ended December 31, 2010 - $0.2 million) of stock-based compensation.

The unproved oil and natural gas properties at June 30, 2011 consist of exploration lands held in Colombia, Argentina, Peru, and Brazil, including additions related to the newly acquired Petrolifera assets. As at June 30, 2011, the Company had $307.2 million (December 31, 2010 - $228.8 million) of unproved assets in Colombia, $58.8 million (December 31, 2010 - $9.4 million) of unproved assets in Argentina, $31.7 million (December 31, 2010 - $28.2 million) of unproved assets in Peru, and $36.6 million (December 31, 2010 - $12.4 million) of unproved assets in Brazil for a total of $434.3 million (December 31, 2010 - $278.8 million). 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.

6. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share and two shares are designated as special voting stock, par value $0.001 per share. As at June 30, 2011, outstanding share capital consists of 260,977,461 common voting shares of the Company, 8,915,318 exchangeable shares of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013, and 7,811,112 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 shareholder 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.

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Warrants

At June 30, 2011, the Company had 6,298,230 warrants outstanding to purchase 3,149,115 common shares for $1.05 per share, expiring between June 20, 2012 and June 30, 2012 and 4,125,036 Replacement Warrants outstanding, issued upon the acquisition of Petrolifera (Note 3), to purchase 4,125,036 common shares for CDN$9.67, expiring August 28, 2011. For the six months ended June 30, 2011, 525,817 common shares were issued upon the exercise of 1,051,634 warrants (six months ended June 30, 2010, 8,352,494 common shares were issued upon the exercise of 9,559,050 warrants). Included in warrants exercised in the six months ended June 30, 2010 were 7,145,938 warrants to purchase 7,145,938 common shares for $14.4 million, assumed on the acquisition of Solana in November 2008.

The fair value of the Replacement Warrants as of June 30, 2011 was determined using the Black-Scholes option pricing model with the following assumptions:

Exercise price (CDN dollars per warrant)	$	9.67
Risk-free interest rate		1.2	%
Expected life	0.16 Years
Volatility		42	%
Expected annual dividend per share	Nil
Estimated fair value per warrant (CDN dollars)	$	0.003

The consolidated statement of operations for the three months ended June 30, 2011 includes a n unrealized gain arising from the change in fair value of the Replacement Warrants of $1.3 million.

Stock Options

As at June 30, 2011, the Company has a 2007 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. The number of shares of common stock available for issuance thereunder is 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 six months ended June 30, 2011, 670,881 common shares were issued upon the exercise of 670,881 stock options (six months ended June 30, 2010 – 1,268,993). The following options were outstanding as of June 30, 2011:

	Number of Outstanding			Weighted Average Exercise Price
	Options			$/Option
Balance, December 31, 2010		10,943,058			3.49
Granted in 2011		3,700,996			8.25
Exercised in 2011		(670,881	)		(2.95	)
Forfeited in 2011		(62,501	)		(4.09	)
Balance, June 30, 2011		13,910,672			4.78

The weighted average grant date fair value for options granted in the six months ended June 30, 2011 was $5.07 (six months ended June 30, 2010 - $3.33). The intrinsic value of options exercised for the three months ended June 30, 2011 was $3.4 million (three months ended June 30, 2010 - $4.8 million).

The table below summarizes stock options outstanding at June 30, 2011:

	Number of Outstanding		Weighted Average Exercise Price		Weighted Average
Range of Exercise Prices ($/option)	Options		$/Option		Expiry Years
0.50 to 2.00		1,369,171		1.14		5.1
2.01 to 3.50		5,072,752		2.46		7.2
3.51 to 5.50		466,666		4.43		8.3
5.51 to 7.00		3,141,087		5.93		8.6
7.01 to 8.40		3,860,996		8.24		7.0
Total		13,910,672		4.78		6.9

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The aggregate intrinsic value of options outstanding at June 30, 2011 is $31.7 million (December 31, 2010 - $49.9 million) based on the Company’s closing stock price of $6.61 (December 31, 2010 - $8.05) at that date. At June 30, 2011, there was $17.7 million (December 31, 2010 - $6.1 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next three years. As at June 30, 2011, 5,911,291 (December 31, 2010 – 5,426,367) options were exercisable.

For the six months ended June 30, 2011, the stock-based compensation expense was $6.2 million (six months ended June 30, 2010 - $3.6 million) of which $5.4 million (six months ended June 30, 2010 - $2.9 million) was recorded in general and administrative expenses and $0.5 million was recorded in operating expenses in the consolidated statement of operations (six months ended June 30, 2010 – $0.5 million). For the six months ended June 30, 2011, $0.3 million of stock-based compensation was capitalized as part of exploration and development costs (six months ended June 30, 2010 – $0.2 million).

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table. The Company uses historical data to estimate option exercises, expected term and employee departure behavior used in the Black-Scholes option pricing model. Expected volatilities used in the fair value estimate are based on historical volatility of the Company’s stock. The risk-free rate for periods within the contractual term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Dividend yield (per share)	$nil			$nil			$nil			$nil
Volatility		80	%		89	%		81	%		90	%
Risk-free interest rate		1.2	%		0.5	%		1.3	%		0.4	%
Expected term	4 - 6 years			3 years			4 - 6 years			3 years
Estimated forfeiture percentage (per year)		4	%		10	%		4	%		10	%

Weighted average shares outstanding

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
Weighted average number of common and exchangeable shares outstanding		277,297,728			254,344,474		269,159,453			251,234,950
Shares issuable pursuant to warrants		2,728,361			5,297,738		2,789,122			5,302,755
Shares issuable pursuant to stock options		5,191,288			4,210,812		6,079,268			4,384,964
Shares to be purchased from proceeds of stock options		(765,841	)		-		(497,717	)		-
Weighted average number of diluted common and exchangeable shares outstanding		284,451,536			263,853,024		277,530,126			260,922,669

Net Income per share

For the three months ended June 30, 2011, 4,125,036 Replacement Warrants and 3,815,996 options to purchase common shares (for the six months ended June 30, 2011 4,125,036 Replacement Warrants and 3,219,996 options to purchase common shares) were excluded from the diluted income per share calculation as the instruments were anti-dilutive. For the three months ended June 30, 2010, options to purchase 3,435,000 common shares (for the six months ended June 30, 2010, options to purchase 3,250,000 common shares) were excluded from the diluted income per share calculation as the instruments were anti−dilutive.

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7. Asset Retirement Obligations

As at June 30, 2011 the Company’s asset retirement obligations were comprised of Colombian obligations in the amount of $4.7 million (December 31, 2010 - $3.7 million), Argentine obligations in the amount of $5.7 million (December 31, 2010 - $1.1 million) and Brazil obligations in the amount of $0.4 million (December 31, 2010 - $nil). As at June 30, 2011, the undiscounted asset retirement obligations were $32.1 million (December 31, 2010 - $8.7 million). Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties were as follows:

	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2011			December 31, 2010
Balance, beginning of period	$	4,807		$	4,708
Settlements		(309	)		(286	)
Disposal		-			(720	)
Liability incurred		1,088			719
Liability assumed in a business combination (Note 3)		4,901			-
Foreign exchange		23			58
Accretion		280			328
Balance, end of period	$	10,790		$	4,807

Asset retirement obligation - current	$	322		$	338
Asset retirement obligation - long term		10,468			4,469
Balance, end of period	$	10,790		$	4,807

8. Taxes

The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income before income taxes for the following reasons:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2011			2010
Income before income taxes	$	99,969		$	51,366
		35	%		3 5	%
Income tax expense expected		34,989			17,978
Other permanent differences		(1,634	)		3,960
Foreign currency translation adjustments		4,956			5,638
Impact of foreign taxes		(3,134	)		(1,580	)
Enhanced tax depreciation incentive		-			(2,921	)
Stock based compensation		1,825			1,014
Increase in valuation allowance		24,065			3,354
Branch and other foreign income pick-up in the United States and Canada		(2,898	)		(3,408	)
Non-deductible third party royalty in Colombia		4,115			-
Non-taxable gain on acquisition		(7,595	)		-
Total income tax expense	$	54,689		$	24,035

Current income tax		63,439			42,066
Deferred tax (recovery)		(8,750	)		(18,031	)
Total income tax expense	$	54,689		$	24,035

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	As at

(Thousands of U.S. Dollars)	June 30, 2011			December 31, 2010
Deferred Tax Assets
Tax benefit of loss carryforwards	$	57,621		$	27,527
Tax basis in excess of book basis		26,854			7,975
Foreign tax credits and other accruals		15,426			16,895
Capital losses		2,448			1,413
Deferred tax assets before valuation allowance		102,349			53,810
Valuation allowance		(87,624	)		(48,958	)
	$	14,725		$	4,852

Deferred tax assets - current	$	2,643		$	4,852
Deferred tax assets - long term		12,082			-
		14,725			4,852

Deferred Tax Liabilities
Long-term - book value in excess of tax basis		(231,558	)		(204,570	)

Net Deferred Tax Liabilities	$	(216,833	)	$	(199,718	)

Equity tax for the six months ended June 30, 2011 of $8.3 million represents a Colombian tax of 6.2% on the balance sheet equity recorded in the Company’s Colombian branches as at January 1, 2011. The equity tax is assessed every four years. The tax for the four-year period from 2011 to 2014 is payable in eight semi-annual installments over the four-year period but is expensed in the first quarter of 2011 at the commencement of the four-year period. Accordingly, the equity tax expense for the previous four-year period was recorded prior to 2010 and no expense is recorded in the first half of 2010. The remainder of the equity tax liability at June 30, 2011 relates to an equity tax liability assumed upon the acquisition of Petrolifera.

As at June 30, 2011, the total amount of Gran Tierra’s unrecognized tax benefits was approximately $13.1 million (December 31, 2010 - $4.2 million), a portion of which, if recognized, would affect the Company’s effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the consolidated statement of operations. As at June 30, 2011, the total amount of interest and penalties included in unrecognized tax benefits in current income tax liabilities in the condensed consolidated balance sheet was approximately $1.8 million. The Company had no interest or penalties included in the consolidated statement of operations for the three and six months ended June 30, 2011 and 2010, respectively.

Changes in the Company's unrecognized tax benefit are as follows:
(Thousands of U.S. Dollars)
Unrecognized tax benefit at January 1, 2011	$	4,175
Reduction of tax position related to prior years		(257	)
Additions to tax position related to the current year		9,190
Unrecognized tax benefit at June 30, 2011	$	13,108

The Company and its subsidiaries file income tax returns in the U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is subject to income tax examinations for the calendar tax years ended 2005 through 2010 in most jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefits disclosed above within the next twelve months.

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As at June 30, 2011, the Company has deferred tax assets relating to net operating loss carryforwards of $57.6 million (December 31, 2010 - $27.5 million) and capital losses of $2.4 million (December 31, 2010 - $1.4 million) before valuation allowances. Of these losses, $48.3 million (December 31, 2010 - $20.5 million) are losses generated by the foreign subsidiaries of the Company. Of the total losses, $1.2 million will begin to expire in 2012 (December 31, 2010 - $nil) and $58.9 million (December 31, 2010 - $28.9 million) will begin to expire thereafter.

9. Accounts Payable and Accrued Liabilities

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

	As at June 30, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Corporate		Total
Property, plant and equipment	$	24,469	$	7,116	$	1,185	$	17,316	$	50,086
Payroll		3,114		412		279		2,129		5,934
Audit, legal, and consultants		-		217		57		1,273		1,547
General and administrative		968		216		133		780		2,097
Operating		56,111		7,959		40		253		64,363
Total	$	84,662	$	15,920	$	1,694	$	21,751	$	124,027

	As at December 31, 2010
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Corporate		Total
Property, plant and equipment	$	32,854	$	10,452	$	8,377	$	1,438	$	53,121
Payroll		3,256		186		-		2,300		5,742
Audit, legal, and consultants		-		140		16		1,676		1,832
General and administrative		1,039		590		70		363		2,062
Operating		43,037		2,141		173		35		45,386
Total	$	80,186	$	13,509	$	8,636	$	5,812	$	108,143

10. Commitments and Contingencies

Leases

Gran Tierra holds four categories of operating leases: compressor, office, vehicle and equipment and housing. The Company pays monthly amounts of $0.2 million for compressors, $0.3 million for office leases, $22,000 for vehicle and equipment leases and $6,000 for certain employee accommodation leases in Canada, Colombia, Argentina, Peru, and Brazil. Future lease payments at June 30, 2011 are as follows:

	As at June 30, 2011
	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	$	10,703	$	5,584	$	4,311	$	808	$	-
Bank debt		31,250		31,250		-		-		-
Software and telecommunication		3,072		1,858		1,032		182		-
Drilling, completion, facility construction and oil transportation services		103,543		71,853		22,069		9,621		-
Consulting		806		806		-		-		-
Total	$	149,374	$	111,351	$	27,412	$	10,611	$	-

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Indemnities

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 the 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 is subject to a third party 10% net profits interest on 50% of the Company’s production from the Costayaco field that arises from the original acquisition in 2006 of 50% of Gran Tierra’s interest in the Chaza Block Contract. There is currently a disagreement between Gran Tierra and the third party as to the calculation of the net profits interest. Gran Tierra and the third party have agreed to resolve this issue through an arbitration which is anticipated to be heard in Texas, in accordance with the rules of the American Arbitration Association, in the fourth quarter of 2011. 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. The disputed amount at June 30, 2011 is $7.0 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, results of operations or cash flows.

11. Financial Instruments, Fair Value Measurements and Credit Risk

The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, bank debt 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. As at June 30, 2011, the fair values of financial instruments approximate their book amounts due to the short term maturity of these instruments except the fair values of derivative financial instruments as discussed below.

None of the these derivative instruments currently qualify as fair value hedges or cash flow hedges, and accordingly, changes in their fair value are 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. The derivative instruments comprise the Replacement Warrants (Notes 3 and 6) and a crude oil collar which expired in February 2010.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. When available, Gran Tierra measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

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The Company does not have any assets or liabilities whose fair value is measured using the Level 1 or 2 methods. The Company classifies the Replacement Warrants as Level 3 and measures their fair values as discussed in Notes 3 and 6.

Most of the Company’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. The book value of the accounts receivable reflects management’s assessment of the associated credit risks.

Additionally, foreign exchange gains/losses result from the fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s deferred tax liability, a monetary liability, which is denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain/loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $110,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

12. Bank Debt and 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 U.S. dollar 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 June 30, 2011, the Company had not drawn down any amounts under this facility.

As part of the acquisition of Petrolifera on March 18, 2011, Gran Tierra assumed a $100 million reserve-backed credit facility with available and outstanding balance as at the Acquisition Date and June 30, 2011 of $31.3 million. This credit facility agreement with a syndicate of banks expires on June 30, 2012. Gran Tierra is required to make three scheduled reserve deposits of $3.8 million per quarter through September 30, 2011 at which time those deposits are applied to repay part of the principal. Two additional principal repayments of $3.8 million are to be made at the end of each of the following quarters with the final settlement of $12 million to be made June 30, 2012 when this agreement expires. As of June 30, 2011, $8.1 million, which includes $0.5 million reserved prior to the acquisition, has been placed in reserve and is recorded as restricted cash in current assets in the Company’s condensed consolidated balance sheet. Under the terms of this credit facility agreement, one-half of any potential farmout proceeds received by Gran Tierra related to Petrolifera's Argentine assets, up to a maximum of $5.0 million, are to be first allocated to reduce the final $12.0 million permanent debt repayment due and payable upon expiry of the agreement in June 2012. Any excess farmout proceeds are then to be evenly allocated to reduce Gran Tierra’s quarterly reserve payments or debt repayments. The credit facility bears interest at LIBOR plus 8.25%, is partially secured by the pledge of the shares of Petrolifera’s subsidiaries and has a provision for a borrowing base adjustment every six months.

Under the terms of the Petrolifera facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. Gran Tierra has classified this credit facility as current as the Company repaid the credit facility on August 5, 2011. A regulation of the Argentine Central Bank establishes that "new indebtedness and renewals of debts with foreign creditors engaged by local residents shall be kept for a minimum 365 days". Petrolifera entered into an amendment of this credit facility on August 4, 2010, which then renewed and restructured the existing debt. As a result, the principal debt that was loaned into Argentina could not be repaid and retired until August 2011.

Interest Expense

Interest expense on the facilities for the 104 day period from the Acquisition Date to June 30, 2011 was $0.8 million. This amount is recorded on the Consolidated Statements of Operations and Retained Earnings as part of general and administrative expense.

Restricted cash

Restricted cash comprises $8.1 million for future debt repayments associated with the credit facility assumed upon the acquisition of Petrolifera (Note 3) and cash resources pledged to secure letters of credit. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts.

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13. Related Party Transaction

On February 1, 2009, the Company entered into a sublease for office space with a company, of which one of Gran Tierra’s directors is a shareholder and director. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $8,800 per month plus approximately $4,500 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 related to the Peru drilling program with a company of which one of Gran Tierra’s directors is a shareholder and director. For the six months ended June 30, 2011, $2.2 million was capitalized and at June 30, 2011, $0.1 million was included in accounts payable related to this contract, the terms of which are consistent with market conditions.

On January 12, 2011, the Company entered into an agreement to sublease office space to a company of which Gran Tierra’s President and Chief Executive Officer serves as an independent Director. The term of the sublease runs from February 1, 2011 to January 30, 2013 and, at $4,400 per month plus approximately $5,700 of operating and other expense, the terms are consistent with market conditions in the Calgary, Alberta, Canada real estate market.

14. Subsequent Event

On August 5, 2011, the Company repaid its bank debt which was assumed upon the acquisition of Petrolifera (Note 12).

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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 values of reserves, business strategy, plans and objectives of our management for future operations and those statements preceded by, followed by or that otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct. 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 25, 2011.

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.

Effective March 18, 2011, we completed the acquisition of Petrolifera Petroleum Ltd. (“Petrolifera”), a Canadian based international oil and gas company which owns working interests in 11 exploration and production blocks; three located in Colombia, three in Peru and five in Argentina.

On August 26, 2010, the Company entered into an agreement to acquire a 70% participating interest in four blocks in Brazil. With the exception of one block which has a producing well, the remaining blocks are unproved properties. The agreement was effective September 1, 2010, subject to regulatory approvals, and the transaction was completed on June 15, 2011. Purchase consideration of $40.1 million, included cash payments of $22.6 million recorded in the Corporate cost centre and an obligation to fund certain exploratory activities, including the drilling of two exploratory wells in the acquired areas. First production contribution from the producing block was recorded in June 2011.

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HIGHLIGHTS

	Three Months Ended June 30,						Six Months Ended June 30,
	2011		2010		% Change		2011		2010		% Change

Production - Barrels of Oil Equivalent ("boe") per Day (1)		18,141		13,376		36		16,354		14,158		16

Prices Realized - per boe	$	97.93	$	68.78		42	$	95.93	$	68.93		39

Revenue and Other Income ($000s)	$	162,120	$	84,114		93	$	284,639	$	177,224		61

Net Income ($000s)	$	31,567	$	17,371		82	$	45,280	$	27,331		66

Net Income Per Share - Basic	$	0.11	$	0.07		57	$	0.17	$	0.11		55

Net Income Per Share - Diluted	$	0.11	$	0.07		57	$	0.16	$	0.10		60

Funds Flow From Operations ($000s) (2)	$	88,572	$	44,323		100	$	155,132	$	98,597		57

Capital Expenditures ($000s)	$	101,489	$	34,856		191	$	170,592	$	54,360		214

	As at
	June 30, 2011		December 31, 2010		% Change

Cash & Cash Equivalents ($000s)	$	211,355	$	355,428		(41	)

Working Capital (including cash & cash equivalents) ($000s)	$	215,360	$	265,835		(19	)

Property, Plant & Equipment ($000s)	$	1,009,055	$	727,024		39

(1) Gas volumes are converted to boes 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. The conversion ratio does not assume price equivalency and the price for a barrel of oil equivalent for natural gas may differ significantly from the price of a barrel of oil.

(2) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under United States Generally Accepted Accounting Principles (“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 Gran Tierra's operating performance and financial results. Investors should be cautioned that this measure should not be construed as an alternative to net income (loss) or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’s method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. Funds flow from operations, as presented, is net income adjusted for depletion, depreciation, accretion and impairment (“DD&A”), deferred taxes, stock-based compensation, unrealized gain on financial instruments, unrealized foreign exchange losses (gains), settlement of asset retirement obligations, equity tax and loss(gain) on acquisition. Reconciliation from funds flow from operations to net income is as follows:

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	Three Months Ended June 30,						Six Months Ended June 30,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2011			2010			2011			2010

Net income	$	31,567		$	17,371		$	45,280		$	27,331
Adjustments to reconcile net income to funds flow from operations
Depletion, depreciation, accretion and impairment		46,965			31,641			110,322			71,984
Deferred taxes		(5,219	)		(7,977	)		(5,406	)		(18,031	)
Stock-based compensation		2,492			1,998			5,945			3,360
Unrealized gain on financial instruments		(1,292	)		-			(1,354	)		(44	)
Unrealized foreign exchange loss		11,644			1,290			16,102			13,997
Settlement of asset retirement obligations		(305	)		-			(309	)		-
Equity taxes		119			-			6,251			-
Loss (gain) on acquisition		2,601			-			(21,699	)		-
Funds flows from operations	$	88,572		$	44,323		$	155,132		$	98,597

Operational Highlights

In the second quarter of 2011, production of oil and gas (net after royalty and inventory adjustments) increased by 36% to 18,141 barrels of oil equivalent per day (“boepd”) compared with the same quarter last year mainly due to a full quarter of production of 2,189 boepd from Petrolifera’s properties in Argentina and absence of any pipeline or other operational disruptions. For the first half of 2011, oil and gas production increased by 16% to 16,354 boepd compared with the first half of 2010. The first quarter of 2011 production was adversely affected by pipeline maintenance in Colombia. In the second quarter of 2010, sections of the Ecopetrol operated Trans Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 7 days in June 2010.

Average prices realized per boe in the three months ended June 30, 2011, increased by 42% to $97.93 compared with the same period last year. For the six months ended June 30, 2011, the average price realized per boe increased by 39% to $95.93 from the comparative period last year.

In the Moqueta field in the Chaza Block in Colombia, in which Gran Tierra has a 100% working interest, the Moqueta-4 delineation well was successfully completed and tested 1,674 barrels of oil per day in the first quarter of 2011 confirming additional oil bearing reservoirs. The Moqueta-5 delineation well was drilled from the same well pad as the Moqueta-4 delineation well and reached total measured depth of 5,309 feet in April 2011. The reservoirs were penetrated approximately 50 feet deeper than in Moqueta-4, increasing the reserve potential of the field. Construction of the Moqueta to Costayaco pipeline was also completed in the second quarter of 2011 with first oil production from Moqueta commencing in June of 2011. Production from Moqueta is expected to be moderate at 500 barrels per day until gas compression facilities are installed .

On June 15, 2011, Gran Tierra received final approvals for the acquisition of a 70% participating interest in Blocks 129, 142, 155 and 224 in the onshore Reconcavo Basin of Brazil and also became the operator of these fields effective from that date. Gran Tierra has now assumed its working interest share of a light oil discovery in Block 155 which is currently producing 500 barrels of oil per day gross from one zone without the assistance of pumps. Two gross development wells are planned to be drilled in the second half of 2011 to grow production from this discovery and Gran Tierra is also committed to drill two exploratory wells in the acquired areas.

Financial Highlights

Higher production levels and improved crude oil prices contributed to a 93% increase in revenue and other income to $162.1 million for the quarter ended June 30, 2011 compared with the same quarter last year. The same contributing factors increased revenue and other income by 61% to $284.6 million for the first half of 2011.

Higher revenues offset partially by increased expenditures and foreign exchange losses resulted in net income of $31.6 million, or $0.11 per basic and diluted share, for the first quarter of 2011. This compares with $17.4 million, or $0.07 per basic and diluted share, recorded in the first quarter of 2010. Net income increased by 66% to $45.3 million, or $0.17 per basic share and $0.16 per diluted share, for the first half of 2011 compared with $27.3 million, or $0.11 per basic share and $0.10 per diluted share, recorded in the same period last year. The improvement came from higher revenues and a $21.7 million gain on acquisition which were partially offset by increased operating and general and administrative (“G&A”) expenses and Colombian equity taxes as well as a $33.4 million ceiling test impairment recorded in the Peru cost center. Foreign exchange losses of $19.7 million were comparable to the losses recorded in the first half of 2010.

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Increased production levels and improved crude oil prices offset partially by increased operating and general and administrative expenses contributed to higher funds flow from operations for both comparative periods.

Our cash and cash equivalents position of $211.4 million at June 30, 2011 decreased from $355.4 million at December 31, 2010 primarily as a result of year-to-date capital expenditures.

Working capital (including cash and cash equivalents) was $215.4 million at June 30, 2011, which is a $50.5 million decrease from December 31, 2010, due mainly to lower cash and cash equivalents and the short term bank debt, offset partially by a $113.3 million increase in accounts receivable due to the timing of payments from Ecopetrol.

Property, plant and equipment as at June 30, 2011 was $1.0 billion, an increase of $282.0 million from December 31, 2010, as a result of additions from the Petrolifera acquisition and the 2011 capital expenditure program, partially offset by DD&A.

Business Environment Outlook

Our revenues have been significantly impacted by the continuing fluctuations in crude oil prices. Crude oil prices are volatile and unpredictable and are influenced by concerns about financial markets and the impact of the 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 continuing uncertainty regarding the Middle East and continued economic instability in the United States and Europe is having an impact on world markets, and Gran Tierra is unable to determine the impact, if any, these events may have on oil prices and demand.

Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt markets. Should we be required to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing shareholders, 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.

2011 Work Program and Capital Expenditure Program

Gran Tierra’s Capital Program continued in the second quarter of 2011 with expenditures of $101.5 million increasing the year to date expenditures to $170.6 million. These expenditure levels represent significant increases from the comparative periods in 2010 of $34.9 million and $54.4 million, respectively. The 2011 expenditures comprised the successful drilling of the Moqueta –4 and –5 wells in the Moqueta field, drilling of Costayaco -12 and -13 development wells in the Costayaco field and pipeline and facility construction in the Chaza Block, Colombia. The 2011 Capital Program also included the acquisition of a 70% participating working interest in four blocks in Brazil with one of the blocks containing a producing well. Also included are drilling costs for the dry and abandoned exploration wells, Taruka-1, Pacayaco-1, San Angel-1, and Canangucho -1 in Colombia, Kanatari-1in Peru, and the Valle Morado GTE.St.VMor-2001 sidetrack well in Argentina.

Gran Tierra’s 2011 work program is intended to create both growth and value through strategic acquisitions of working interests, by leveraging existing assets to increase reserves and production levels and through the construction of pipelines and facilities in the areas with proved reserves. We are financing our capital program through internal cash flows, while retaining financial flexibility with a strong cash position and no debt, so that we can be positioned to undertake further development opportunities and to pursue value-add acquisitions. However, actual capital expenditures may vary significantly from our 2011 work program if unexpected events or circumstances occur, such as new opportunities present themselves, or anticipated opportunities do not come to fruition, which may therefore either increase or decrease the amount of capital expenditures we incur in 2011.

Gran Tierra has planned a 2011 capital spending program of $357 million for exploration and development activities in Colombia ($196 million), Peru ($49 Million), Argentina ($50 million) and Brazil ($62 million), including expenditures related to the newly acquired Petrolifera assets. Of this, $190 million is for drilling, $79 million for infrastructure, $87 million for seismic acquisition and $1 million for other activities. Of the $190 million related to drilling, approximately, $87 million is for exploration and the balance is for delineation and development drilling. We expect that our committed and discretionary 2011 capital program can be funded from cash flow from operations and cash on hand.

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Gran Tierra continues to anticipate full year 2011 NAR production to average between 17,500 and 19,000 barrels of oil equivalent per day.

BUSINESS COMBINATION

On March 18, 2011 (the “Acquisition Date”), we completed our acquisition of all the issued and outstanding common shares and warrants of Petrolifera pursuant to the terms and conditions of the Arrangement Agreement dated January 17, 2011. Petrolifera is a Calgary-based crude oil, natural gas and natural gas liquids exploration, development and production company active in Argentina, Colombia and Peru. For further details reference should be made to Note 3 of the condensed consolidated financial statements.

The acquisition is accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed are recorded at their fair values as at the Acquisition Date and the results of Petrolifera are consolidated with those of Gran Tierra from that date.

The following table shows the allocation of the consideration transferred based on the fair values of the assets and liabilities acquired:

(Thousands of U.S. Dollars)
Consideration Transferred:
Common shares issued net of share issue costs	$	141,690
Replacement warrants		1,354
	$	143,044

Allocation of Consideration Transferred (1):
Oil and gas properties
Proved	$	58,457
Unproved		161,278
Other long term assets		4,417
Net working capital (including cash acquired of $7.7 million and accounts receivable of $6.4 million)		(17,223	)
Asset retirement obligations		(4,901	)
Bank debt		(22,853	)
Other long term liabilities		(14,432	)
Gain on acquisition		(21,699	)
	$	143,044

(1) The allocation of the consideration transferred is not final and is subject to change.

As indicated in the allocation of the consideration transferred, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra recognized a “Gain on acquisition” of $21.7 million in the consolidated statement of operations. The gain reflects the impact on Petrolifera’s pre-acquisition market value resulting from their lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects. Subsequent to the initial allocation of the consideration reported in the first quarter of 2011, further assessment of Petrolifera’s tax position resulted in a reduction of the gain on acquisition to $21.7 million from $24.3 million previously reported. A corresponding adjustment has been made to the net working capital deficiency assumed.

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The acquisition was effective March 18, 2011 and the results of Petrolifera have been consolidated with Gran Tierra since that date. Production from the Petrolifera properties amounted to 1,245 boepd (2,189 boepd for the second quarter of 2011) with revenues of $10.9 million (second quarter 2011 - $9.7 million). With the exception of gain on acquisition described above, the impact of Petrolifera on Gran Tierra’s net income for the six months ended June 30, 2011 was not material.

REVIEW OF CONSOLIDATED RESULTS

	Three Months Ended June 30,									Six Months Ended June 30,
Consolidated Results of Operations	2011			2010			% Change			2011			2010			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	161,664		$	83,717			93		$	283,960		$	176,649			61
Interest		456			397			15			679			575			18
		162,120			84,114			93			284,639			177,224			61

Operating expenses		23,160			9,529			143			39,556			19,714			101
Depletion, depreciation, accretion, and impairment		46,965			31,641			48			110,322			71,984			53
General and administrative expenses		16,410			9,594			71			30,048			16,784			79
Equity tax		221			-			-			8,271			-			-
Financial instruments gain		(1,292	)		-			-			(1,522	)		(44	)		-
Loss (gain) on acquisition		2,601			-			-			(21,699	)		-			-
Foreign exchange loss		14,495			3,126			(364	)		19,694			17,420			(13	)

		102,560			53,890			90			184,670			125,858			47

Income before income taxes		59,560			30,224			97			99,969			51,366			95
Income tax expense		(27,993	)		(12,853	)		118			(54,689	)		(24,035	)		128

Net income	$	31,567		$	17,371			82		$	45,280		$	27,331			66

Production, Net of Royalties

Oil and NGL's ("bbl") (1)		1,594,735			1,204,254			32			2,888,188			2,545,936			13
Natural gas ("mcf") (1)		336,837			77,550			334			431,154			100,068			331

Total production ("boe") (1) (2) (3)		1,650,875			1,217,179			36			2,960,047			2,562,614			16

Average Prices

Oil and NGL's ("per bbl")	$	100.68		$	69.25			45		$	97.82		$	69.23			41
Natural gas ("per mcf")	$	3.32		$	4.09			(19	)	$	3.31		$	4.05			(18	)

Consolidated Results of Operations ("per boe")

Oil and natural gas sales	$	97.93		$	68.78			42		$	95.93		$	68.93			39
Interest		0.28			0.33			(15	)		0.23			0.22			5

		98.21			69.11			42			96.16			69.15			39

Operating expenses		14.03			7.83			79			13.36			7.69			74
Depletion, depreciation, accretion, and impairment		28.45			26.00			9			37.27			28.09			33
General and administrative expenses		9.94			7.88			26			10.15			6.55			55
Equity tax		0.13			-			-			2.79			-			-
Foreign exchange loss		8.78			2.57			(242	)		6.65			6.80			2
Loss(gain) on acquisition		1.57			-			-			(7.33	)		-			-
Financial instruments gain		(0.78	)		-			-			(0.51	)		(0.02	)		-

		62.12			44.28			40			62.38			49.11			27

Income before income taxes		36.09			24.83			45			33.78			20.04			69
Income tax expense		(16.95	)		(10.56	)		61			(18.48	)		(9.38	)		97

Net income	$	19.14		$	14.27			34		$	15.30		$	10.66			44

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

(2)	Natural gas liquids (“NGL”) volumes are converted to a barrel of oil equivalent (“boe”) on a one-to-one basis with oil.

(3)	Gas volumes are converted to boe at the rate of six thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices.

Consolidated 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, Peru and Corporate with the latter including the results of our activities in Brazil. For the three and six month periods ended June 30, 2011, Colombia generated 92% and 93%, respectively, of our revenue and other income. For the three and six months ended June 30, 2010, Colombia generated 96% of our revenue and other income. The decline in percentage contribution reflects the full quarter revenue contribution from Petrolifera that is primarily generated in Argentina.

Net income of $31.6 million, or $0.11 per share basic and diluted, was recorded for the three months ended June 30, 2011 compared to net income of $17.4 million, or $0.07 per share basic and diluted, for the same period in 2010. Higher oil revenues due to increased production and higher realized crude oil prices were partially offset by increased operating, DD&A and G&A expenses, and foreign exchange losses.

For the first half of the year, net income increased to $45.3 million, a 66% improvement from the same period last year. On a per share basis, net income improved to $0.17 per share basic and $0.16 per share diluted from the $0.11 basic and $0.10 diluted per share recorded in the first half of 2010. Improved revenues due to production and crude oil price increases were partially offset by higher operating and G&A expenses, a ceiling test impairment in the Peru Segment and Colombian equity tax. The results for the first six months of 2011 were also positively affected by a gain recorded on acquisition of Petrolifera. Foreign exchange losses recorded in the first half of 2011 were comparable to prior year.

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Crude oil and NGL production , net after royalties, for the three months ended June 30, 2011 increased to 1,594,735 barrels, a 32% improvement from the same quarter last year. Absence of pipeline interruptions, full quarter contribution from Petrolifera (158,996 barrels) and improved production levels from the Costayaco field contributed to this increase. For the first six months of 2011, production of crude oil increased by 13% to 2,888,188 barrels due to terminal maintenance programs in Colombia which had an adverse effect on pipeline deliveries. In the second quarter of 2010, sections of the Ecopetrol operated Trans Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 7 days in June 2010.

Average realized crude oil prices for the current quarter increased to $100.68 per barrel ($97.82 for the first six months of 2011) from $69.25 per barrel for the first three months of 2010 ($69.23 for the first six months of 2010) reflecting higher West Texas Intermediate (“WTI”) oil prices. We received a premium to WTI during the first six months of 2011.

Increased production coupled with higher crude oil prices resulted in a 93% increase to $162.1 million in revenue and interest for the second quarter of 2011 and a 61% increase to $284.6 million for the first half of 2011, in comparison with prior year periods.

Operating expenses for the second quarter of 2011 amounted to $23.2 million, compared with $9.5 million recorded in the same quarter last year. The increase in operating expenses was mainly due to higher workover, fuel and power, water injection and trucking costs as well as a full quarter inclusion of Petrolifera operating costs ($4.5 million). Operating expenses for the first six months of 2011, increased to $39.6 million from $19.7 million last year due to the same factors. On a per unit basis, operating costs per boe increased to $14.03 from $7.83 for the second quarter and to $13.36 from $7.69 for the first half of the year compared to the prior year periods.

DD&A expense for the second quarter of 2011 increased to $47.0 million compared to $31.6 million for the same quarter in 2010. The increase was attributable to higher production levels as the depletion rate at $28.45 per boe remained comparable to the same quarter last year. Increased costs in the depletable pools were offset by higher reserves. DD&A expense for the second quarter of 2011 also included $4.2 million representing a full quarter of DD&A related to properties acquired from Petrolifera. For the six months ended June 30, 2011, DD&A expense increased to $110.3 million from $72.0 million recorded in the same period last year due to increased production and a $33.4 million ceiling test impairment recorded in our Peru cost center in the first quarter of 2011. This resulted in an increase in the effective depletion rate to $37.27 per boe in the current six month period compared with $28.09 per boe recorded in the same period last year.

G&A expenses of $16.4 million and $30.0 million for the three and six months ended June 30, 2011, respectively, were higher than comparable periods last year due to increased employee related costs reflecting the expanded operations in all business units as well as the Corporate Segment and $1.2 million of expenses associated with the acquisition of Petrolifera. Expenses for the second quarter of 2011 also included a full quarter of G&A expenses for Petrolifera ($2.9 million) and interest expense on the Petrolifera bank debt ($0.7 million). G&A expenses per boe increased 26% to $9.94 per boe for the current quarter, compared to $7.88 per boe for the second quarter of 2010, and increased by 55% to $10.15 per boe for the first six months ended June 30, 2011 compared to $6.55 for the same period in 2010 due to the same factors.

Equity tax represents a Colombian tax of 6.2% on the balance sheet equity recorded in our Colombia branches at January 1, 2011.

The foreign exchange losses result primarily from the translation of deferred tax liabilities denominated in Colombia Pesos. Under U.S. GAAP, these deferred taxes which arose from the acquisition of Solana are considered a monetary liability and are required to be translated at each balance sheet date to U.S dollars resulting in exchanges gains or losses. The foreign exchange losses recorded in both comparative periods resulted from the weakening of the U.S. dollar in relation to Colombian Peso.

Income tax expense for the three months ended June 30, 2011 amounted to $28.0 million compared to $12.9 million recorded in the same period in 2010. For the six months ended June 30, 2011, income tax expense amounted to $54.7 million compared to $24.0 million recorded in the first half of 2010. In 2011, higher income before income taxes resulted in increased income taxes. The effective income tax rate for the second quarter of 2011 was 47% compared with 43% the same quarter last year due to the increase in the valuation allowance. For the first six months of 2011, the effective income tax rate was 55% compared with 47% in the same period last year due to the increase in the valuation allowance on losses incurred mainly in Peru offset partially by the inclusion of the non-taxable gain on acquisition. The variance in the effective tax rates for both comparative periods compared to the 35% U.S. statutory rate is attributable to the same factors and other permanent difference.

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REVIEW OF OPERATIONS IN COLOMBIA

	Three Months Ended June 30,							Six Months Ended June 30,
Segmented Results of Operations – Colombia	2011		2010		% Change			2011		2010		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	148,473	$	80,603		84		$	265,777	$	170,036		56
Interest		158		142		11			245		219		12

		148,631		80,745		84			266,022		170,255		56

Operating expenses		15,558		7,288		113			28,343		15,390		84
Depletion, depreciation and accretion		39,609		30,321		31			69,645		65,327		7
General and administrative expenses		5,426		3,727		46			8,739		6,799		29
Equity tax		221		-		-			8,271		-		-
Foreign exchange loss		14,088		2,320		(507	)		19,409		16,890		(15	)

		74,902		43,656		72			134,407		104,406		29

Segment income before income taxes	$	73,729	$	37,089		99		$	131,615	$	65,849		100

Production, Net of Royalties

Oil and NGL's ("bbl") (1)		1,380,210		1,138,847		21			2,583,825		2,404,416		7
Natural gas ("mcf") (1)		60,315		77,550		(22	)		115,572		100,068		15

Total production ("boe") (1) (2) (3)		1,390,262		1,151,772		21			2,603,087		2,421,094		8

Average Prices

Oil and NGL's ("per bbl")	$	107.39	$	70.50		52		$	102.68	$	70.55		46
Natural gas ("per mcf")	$	4.25	$	4.11		3		$	4.15	$	4.09		1

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	106.80	$	69.98		53		$	102.10	$	70.23		45
Interest		0.11		0.12		(8	)		0.09		0.09		-

		106.91		70.10		53			102.19		70.32		45

Operating expenses		11.19		6.33		77			10.89		6.36		71
Depletion, depreciation and accretion		28.49		26.33		8			26.75		26.98		(1	)
General and administrative expenses		3.90		3.24		20			3.36		2.81		20
Equity tax		0.16		-		-			3.18		-		-
Foreign exchange loss		10.13		2.01		(404	)		7.46		6.98		(7	)

		53.87		37.91		42			51.64		43.13		20

Segment income before income taxes	$	53.04	$	32.19		65		$	50.55	$	27.19		86

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

(2)	Natural gas liquids (“NGL”) volumes are converted to boe on a one-to-one basis with oil.

(3)	Gas volumes are converted to ("boe") at the rate of six thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices.

Segmented Results of Operations – Colombia

For the three and six months ended June 30, 2011, income before income taxes from Colombia amounted to $73.7 million and $131.6 million respectively, compared to $37.1 million and $65.8 million in the same periods in 2010. The increases are mainly the result of increased oil revenues due to higher crude oil production and improved prices, offset partially by increases in operating and G&A expenses, DD&A equity tax and foreign exchange losses.

For the three months ended June 30, 2011, production of crude oil and NGLs , net after royalties, increased by 21% to 1,380,210 barrels compared to 1,138,847 barrels for the same period in 2010. The increase is primarily due to improved production levels from the Costayaco oil field and absence of any pipeline disruptions during the quarter. Production for the first six months of 2011 amounted to 2,583,825 barrels compared to 2,404,416 barrels, an increase of 7% from the same period last year. The first quarter production was adversely affected by the maintenance program at the Tumaco Port crude offloading terminal between December 28, 2010 and February 7, 2011 which reduced sales through the Ecopetrol-operated Trans-Andean oil pipeline. In the second quarter of 2010, sections of the Ecopetrol operated Trans Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 7 days in June 2010.

As a result of achieving gross field production of five million barrels in our Costayaco field during the month of September 2009, Gran Tierra is now subject to an additional government royalty payable. This royalty is calculated on 30% of the field production revenue over an inflation adjusted trigger point. That trigger point for Costayaco crude oil is $31.29 for 2011. 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 and $100 WTI price per barrel are approximately 27.9%, including the additional government royalty of approximately 20.5%. The National Hydrocarbons Agency sliding scale royalty at 17,000 barrels of oil per day is approximately 9.2% and this royalty is deductible prior to calculating the additional government royalty.

Revenue and interest for the three and six months ended June 30, 2011 increased by 84% to $148.6 million and by 56% to $266.0 million, respectively, from comparable prior year periods. Revenue and interest were positively impacted by an increase in net realized crude oil prices in 2011 compared to 2010 as well as increased production. The average net realized price for crude oil increased by 52% to $107.39 per barrel for the three months ended June 30, 2011 compared to the same period last year. For the first six months of this year, the average realized price increased by 46% to $102.68 per barrel from the same period last year. We received a premium to WTI during the first half of 2011.

O perating expenses for the three months ended June 30, 2011 increased to $15.6 million from $7.3 million in the same period last year. For the six months ended June 30, 2011 operating expenses increased to $28.3 million compared to $15.4 million in the same period in 2010. The increased operating expenses resulted from higher workover, fuel and power, water injection and trucking costs. On a per barrel basis, operating expenses for the second quarter of 2011 increased to $11.19 compared to $6.33 incurred for the same period last year ($10.89 for the first six months of 2011 versus $6.36 in the same period last year), for the same reasons mentioned above.

For the quarter ended June 30, 2011, DD&A expense increased to $39.6 million from $30.3 million recorded in the same period in 2010. The increase was attributable to higher production levels as the depletion rate at $28.49 per boe remained comparable to the same quarter last year. Increased levels of costs in our depletable pools were offset by higher reserves. DD&A expense for the first half of 2011 amounted to $69.6 million essentially unchanged from the same period last year. The impact of an 8% increase in production was essentially offset by higher crude oil proved reserves as the depletion rate of $26.75 per boe remained essentially unchanged from the same period last year.

An increased level of development and operating activities and higher stock-based compensation expense resulted in G&A expense increasing to $5.4 million ($3.90 per boe) for the three months ended June 30, 2011 from $3.7 million ($3.24 per boe) incurred for the same period in 2010. For the six months ended June 30, 2010, G&A expense increased to $8.7 million ($3.36 per boe) from $6.8 million ($2.81 per boe) incurred for the first six months of 2010, for the same reasons cited above.

Equity tax of $8.3 million for the six months ended June 30, 2011 represents a Colombian tax of 6.2% on the balance sheet equity recorded in our Colombian branches at January 1, 2011. The equity tax is assessed every four years. The tax for the four-year period from 2011 to 2014 is payable in eight semi-annual installments over the four-year period but is expensed in the first quarter of 2011 at the commencement of the four-year period. Accordingly, the equity tax expense for the previous four-year period was recorded prior to 2010 and no expense is recorded in the comparative periods for 2010.

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The results for the three months ended June 30, 2011 include a foreign exchange loss of $14.1 million, of which $11.6 million is an unrealized non cash foreign exchange loss on the translation of Colombian peso denominated deferred taxes to the U.S. dollar functional currency. Under GAAP, such deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation results in the recognition of unrealized exchange losses or gains. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $110,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar. For the same quarter in 2010, the foreign exchange loss recorded was $2.3 million loss, of which $1.3 million was unrealized. For the six months ended June 30, 2011 the foreign exchange loss of $19.4 million (2010: $16.9 million) included an unrealized loss of $16.0 million (2010: $13.8 million).

Capital Program - Colombia

Our capital expenditures in Colombia amounted to $54.2 million for the second quarter of 2011 bringing the total expenditures for the first half of 2011 to $96.5 million, an approximate 100% increase from the comparative periods in 2010. In 2010, we spent $28.9 million in the second quarter and $46.5 million in the first six months of the year. The following provides a breakdown of our capital expenditures in the comparative periods of 2011 and 2010:

Capital Program – Colombia	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of U.S. Dollars)	June 30, 2011		June 30, 2010		June 30, 2011		June 30, 2010

Drilling and completion	$	26.4	$	17.7	$	56.8	$	25.1
Facilities and equipment		9.9		7.8		15.0		13.2
Geological and geophysical		4.3		2.7		5.1		7.2
Other		13.6		0.7		19.6		1.0
		54.2		28.9		96.5		46.5

The significant elements of Gran Tierra’s 2011 Capital Program in Colombia are summarized below:

·	Moqueta Field, Chaza Block (100% working interest and Operator)

The Moqueta-4 delineation well was completed and tested in the first quarter of 2011 and confirmed oil bearing reservoirs in the Villeta T Sandstone, the Lower U Sandstone and the Caballos formations. The Moqueta-5 deviated delineation well was drilled from the same well pad as the Moqueta-4 delineation well and reached total measured depth of 5,309 feet in April 2011. Initial production tests at Moqueta-5 were conducted on the T Sandstone reservoir and will eventually be performed on all zones. Testing over 10 days resulted in production rates of 730 barrels of oil per day with a jet pump. In the second quarter of 2011, construction of facilities at the Moqueta field commenced. Gran Tierra completed the 6 inch diameter, 8 km pipeline connecting the Moqueta and Costayaco infrastructure. First production tests occurred on June 29, 2011 and will continue throughout 2011 as we test the reservoir productivity and pressure response. Average production from the Moqueta field is expected to be modest, at approximately 500 barrels of oil per day for the second half of 2011. Production is expected to begin ramping up in 2012 to levels that will be determined once reservoir performance data has been acquired, the full aerial extent of the field has been determined, and the final development concept decided.

·	Costayaco Field, Chaza Block (100% working interest and Operator)

Drilling operations concluded in the first quarter of 2011 on the Costayaco-12 and -13 development wells, which were drilled as infill production wells to test the respective northern and southern extensions of the Costayaco field. Production from the Costayaco-12 and -13 wells is intended to assist in maintaining production plateau at the Costayaco field; these wells will be converted to water-injectors to assist with pressure maintenance in the field later in the Costayaco field life. In the second quarter of 2011, drilling operations commenced on the Costayaco-14 development well, which is planned to be used as a water injector well to assist in maintaining reservoir pressure. The field was connected to the national electrical system during the quarter, which is expected to marginally improve operating costs in the area going forward.

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·	Canangucho Prospect, Chaza Block (100% working interest and Operator)

The Canangucho-1 exploration well reached total depth on March 23, 2011. After the evaluation of wireline logs, it was determined that the T Sandstone and Caballos formations were water bearing. As a result, the Canangucho well was plugged and abandoned.

·	Juanambu Field, Guayuyaco Block (70% working interest and Operator)

The Juanambu-3 development well began drilling on March 3, 2011. Drilling operations were completed in April, 2011. The U Sandstone, T Sandstone and Caballos formations were fractured during a workover in the second quarter. All formations tested oil at improved rates over the original test.

·	Garibay – Melero -1 (50% working interest and Non-Operated

The Melero-1 exploration well reached total depth of 9,748 feet on July 16, 2011. Oil shows in the Mirador Formation were encountered during drilling and oil is interpreted from logs. Repeat Formation Tester data over the zone was inconclusive. A testing program is currently being prepared

·	Taruka Prospect, Piedemonte Sur Block (100% working interest and Operator)

The Taruka-1 exploration well reached total depth on February 7, 2011. The target reservoirs were encountered, but with only poor oil shows. The well was plugged and abandoned.

·	Brillante, Sierra Nevada Block (100% working interest and Operator)

Development of the Brillante gas field is advancing, with first gas sales expected to be initiated in the third quarter of 2011 through compressed natural gas trucking at approximately 2 to 3 million cubic feet per day. A new 275 square kilometer 3D seismic acquisition program is expected to be acquired in the third quarter of 2011, of which 222 square kilometers will be in the Sierra Nevada License and 53 square kilometers will be in the Magdalena license. Construction of the platform for the Brillante SE-2 well has commenced.

Outlook – Colombia

The 2011 capital program in Colombia is $196 million with $108 million allocated to drilling, $38 million to facilities and pipelines and $50 million for geological and geophysical (“G&G”) expenditures. Three additional blocks added to Gran Tierra’s portfolio from Petrolifera were Sierra Nevada, Magdalena, and Turpial.

For the remaining six months of 2011, the drilling program includes the completion of six gross exploration wells and two gross development wells as described below:

Exploration Activities:

·	The Pacayaco-1 ST1 well on the Chaza block of the Putumayo basin is expected to be drilled in the fourth quarter of 2011.

·	Environmental permitting for the Rumiyaco-1 oil exploration well in the Rumiyaco Block of the Putumayo Basin has been approved. Civil construction work began in May 2011 and the well is expected to start drilling in the third quarter of 2011.

·	Melero-1 testing to be completed in the third quarter of 2011.

·	La Vega Este-1 oil exploration well in the Azar Block is on schedule to be drilled in the fourth quarter of 2011.

·	The Turpial-1 exploration well in the Middle Magdalena Basin is expected to begin drilling in the fourth quarter of 2011 targeting a heavy oil prospect on the Turpial Block.

·	The Brillante SE-2 well is expected to be drilled in the third quarter of 2011. The Brillante SE-2 well is expected to evaluate the significant potential gas resource discovered by Brillante SE-1x.

Development and Delineation Activities:

Moqueta-6, expected to spud in third quarter of 2011, will be drilled as a deviated well from the Moqueta-4 and -5 surface location in order to further investigate the down dip limits of the oil columns encountered in the Villeta U, Villeta T and Caballos formation reservoirs. Subject to further drilling engineering work, the bottom hole location is approximately 600 meters northwest of Moqueta-4. Planning is underway for Moqueta-7, expected to be drilled in the first quarter of 2012 at a new surface location approximately 1,750 meters west of Moqueta-4. This location will allow additional appraisal of the down dip extent of the field. Moqueta-7 could be used as an oil producer or water injector depending on the well results.

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·	Costayaco-14 water injection well is expected to be completed in early third quarter.

Facilities:

·	Facility construction will include ongoing development of the Moqueta field and further facility work at Costayaco and Brillante.

Seismic:

New 3D seismic acquisition is expected to start in the third quarter to assist in refining the mapping of the Moqueta field and planning further delineation and development drilling. 3-D seismic programs in Moqueta along with seismic programs in Brillante and three other blocks are expected to be completed by December 2011.

REVIEW OF OPERATIONS IN ARGENTINA

	Three Months Ended June 30,									Three Months Ended June 30,
Segmented Results of Operations - Argentina	2011			2010			% Change			2011			2010			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	12,857		$	3,114			313		$	17,849		$	6,613			170
Interest		28			3			833			28			19			47

		12,885			3,117			313			17,877			6,632			170

Operating expenses		7,428			2,113			252			10,975			4,142			165
Depletion, depreciation, accretion, and impairment		5,505			1,224			350			6,652			6,491			2
General and administrative expenses		2,779			885			214			3,697			1,605			130
Foreign exchange loss		272			4			-			82			147			(44	)

		15,984			4,226			278			21,406			12,385			73

Segment loss before income taxes	$	(3,099	)	$	(1,109	)		179		$	(3,529	)	$	(5,753	)		(39	)

Production, Net of Royalties

Oil and NGL's ("bbl") (1) (2)		210,512			65,407			222			300,350			141,520			112
Natural gas ("mcf") (2)		276,522			-			-			315,582			-			-

Total production ("boe") (2) (3)		256,599			65,407			292			352,947			141,520			149

Average Prices

Oil and NGL's ("per bbl")	$	57.01		$	47.61			20		$	56.27		$	46.73			20
Natural gas ("mcf") (1)	$	3.11		$	-			-		$	3.00		$	-			-

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	50.11		$	47.61			5		$	50.57		$	46.73			8
Interest		0.11			0.05			120			0.08			0.13			(38	)

		50.22			47.66			5			50.65			46.86			8

Operating expenses		28.95			32.31			(10	)		31.10			29.27			6
Depletion, depreciation, accretion, and impairment		21.45			18.71			15			18.85			45.86			(59	)
General and administrative expenses		10.83			13.53			(20	)		10.47			11.34			(8	)
Foreign exchange loss		1.06			0.06			-			0.23			1.04			75

		62.29			64.61			(4	)		60.65			87.51			(31	)

Segment loss before income taxes	$	(12.07	)	$	(16.95	)		(29	)	$	(10.00	)	$	(40.65	)		(75	)

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

(2)	Natural gas liquids (“NGL”) volumes are converted to boe on a one-to-one basis with oil.

(3)	Gas volumes are converted to barrel of oil equivalent (“boe”) at the rate of six thousand cubic feet (“mcf”) of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices.

Segmented Results of Operations – Argentina

For the three months ended June 30, 2011 the pre-tax loss from Argentina was $3.1 million compared to a pre-tax loss of $1.1 million recorded in the same period in 2010. Increased oil and gas sales were more than offset by higher operating and G&A expenses as well as increased DD&A. For the six months ended June 30, 2011, the pre-tax loss was $3.5 million compared to $5.8 million of pre-tax loss recorded in the same period last year. For the first half of the year, higher oil and gas revenues were partially offset by increases in operating and G&A expenses. Operations of our Argentine Segment in 2011 were significantly affected by the inclusion of Petrolifera operations since March 19, 2011. The impact of Petrolifera on the financial and operational highlights of our business segment in Argentina is discussed below.

Crude oil and NGL production , net after 12% royalties, increased to 216,428 barrels for the three months ended June 30, 2011 compared to 65,407 barrels for the same period in 2010. For the six months ended June 30, 2011, production levels increased by 116% to 306,266 barrels compared to 141,520 barrels produced in the same period in 2010. The increase resulted from the inclusion of Petrolifera production of 178, 618 barrels beginning March 19, 2011.

In the second quarter of 2011, Natural Gas Sales which all come from the Petrolifera properties amounted to 241 million cubic feet bringing the total post acquisition sales since March 19, 2011 to 280 million cubic feet.

Overall, total production of oil and gas from the Argentine segment increased by 292% to 256,599 boe for the second quarter of 2011 and by 149% to 352,947 boe for the first half of the year.

Due to the local regulatory regimes, the price we currently receive for production from our blocks is approximately $57 per barrel. Furthermore, currently most oil and gas producers in Argentina are operating without sales contracts for periods longer than several months. Along with most other oil producers in Argentina we are continuing deliveries to the refineries and are negotiating a price for those deliveries on a regular and short term basis.

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With a 20% improvement in regulated crude oil prices, and increased production levels due to the inclusion of Petrolifera oil and gas production, our revenues have increased by 313% to $12.9 million in the three months ended June 30, 2011 compared to the same period in 2010. For the six months ended June 30, 2011, an 20% crude oil price improvement coupled with higher production of crude oil and the recording of natural gas sales from the properties acquired from Petrolifera, resulted in an increase in revenue levels of 170% to $17.9 million compared to the same period in 2010.

Operating expenses for the three months ended June 30, 2011, amounted to $7.4 million, or $28.95 per boe, compared to $2.1 million, or $32.31 per boe, incurred in the same quarter last year. The increase was primarily due to the inclusion of Petrolifera operating expenses ($4.5 million) as well as increased workovers expenses. Operating expenses for the first half of 2011 increased to $11.0 million ($31.10 per boe) compared to $4.1 million ($29.27 per boe) for the same period a year ago due to the same factors (Petrolifera - $5.1 million).

DD&A expense for the second quarter of 2011 was $5.5 million compared with $1.2 million recorded in the same quarter last year. The increase is primarily due to the inclusion of full quarter DD&A for Petrolifera ($4.2 million). On a boe basis the DD&A rate increased to $21.45 from $18.71 due to higher cost pools offset partially by increased reserves. For the first half of 2011, DD&A expense was comparable to the same period in 2010. DD&A for the six month ending June 30, 2011 includes $4.9 million from Petrolifera. In 2010, DD&A includes a $3.7 million impairment charge. DD&A rate per boe in 2011 is $18.85, significantly lower than the $45.86 DD&A rate recorded in the first six months of 2010 due to the inclusion of the impairment charge of $26.14 per boe in 2010.

The G&A expense for the three and six months ending June 30, 2011 increased from the comparable period in 2010 due to the inclusion of Petrolifera G&A since its acquisition ($1.4 million for the three months ended June 30, 2011 and since acquisition).

Capital Program - Argentina

Capital expenditures for the three months ended June 30, 2011, amounted to $7.1 million bringing the total expenditures in the region for the first six months of 2011 to $18.8 million. The 2011 Program mainly included drilling expenses of $17.5 million, facilities expenses of $2.8 million , G&G expenses of $1.3 million and other of $0.5 million . These expenditures were partially offset by proceeds of $3.3 million from the farm out of the Santa Victoria Property.

Capital expenditures in Argentina for the three months ended June 30, 2010, were $3.8 million ($4.5 million for the six months ended June 30, 2010). The 2010 Program mainly included G&G expenditures in Valle Morado and drilling expenses in Valle Morado and El Chivil properties.

The significant elements of Gran Tierra’s 2011 Capital Program in Argentina are summarized below:

·	Properties acquired from Petrolifera:

Gran Tierra acquired six blocks in the Nuequen Basin from Petrolifera: Puesto Morales, Puesto Morales Este, Rinconada, Vaca Mahudia, Puesto Guevara and Gobernader.

·	Valle Morado Field, Valle Morado Block

The sidetrack drilling operation on the Valle Morado GTE.St.VMor-2001 well was suspended in February 2011 and the well has been abandoned due to the poor condition of the casing in the discovery well.

·	El Chivil, Neuquen Basin

Gran Tierra completed the workover program in El Chivil in the second quarter of 2011, which has helped stabilize production.

·	Puesto Morales Blocks, Neuquén Basin

Gran Tierra has completed workovers on 10 of the planned 16 well workover program. G&G work is being done to optimize the location of the six planned development wells, which are expected to be drilled in the fourth quarter of 2011. The intention of the drilling program is to improve recovery in the remaining reserves, minimize water channeling, and subsequently growing production. Three water injector wells have been postponed into early 2012. Since taking over operations in March, production declines of the last several years have been halted and production has now improved to approximately 2,500 barrels of oil equivalent per day, net of royalties, comprised of approximately 1,670 barrels of oil per day and 4.8 million cubic feet of gas per day.

·	Santa Victoria Block, Noroeste Basin (50% working interest and Operator)

We successfully farmed out a 50% interest in the Santa Victoria Block in the Noroeste Basin of northwestern Argentina to Apache Corporation (“Apache”) in March 2011. The joint venture, with Gran Tierra as operator, is evaluating the gas potential of the acreage, with gas-condensate reserves and production proven in the region. Gran Tierra has agreed to proceed with Apache into the second exploration phase, which has a work commitment that will be fulfilled with one exploration well expected to be drilled before year-end 2012 .

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Outlook – Argentina

The 2011 capital program in Argentina is $50 million with $40 million allocated to drilling, $9 million to facilities and pipelines, and $1 million to G&G expenditures.

Gran Tierra’s planned work program for 2011 includes one development well in Palmar Largo, development wells in Puesto Morales /Puesto Morales Este, workovers in El Vinalar and Puesto Morales/Puesto Morales Este, one development well in Surubi, facility construction, and geophysical work.

REVIEW OF OPERATIONS IN PERU

	Three Months Ended June 30,								Six Months Ended June 30,
	2011			2010			% Change		2011			2010			% Change
Segmented Results of Operations - Peru
(Thousands of U.S. Dollars)
Interest	$	134		$	-			-	$	134		$	-			-

Operating expenses	$	108		$	59			83	$	172		$	95			81
Depletion, depreciation, accretion and impairment		1,530			3			-		33,463			11			-
General and administrative expenses		1,000			173			478		1,565			377			315
Foreign exchange (gain) loss		(133	)		7			-		(70	)		8			-

		2,505			242			935		35,130			491			-

Segment loss before income taxes	$	(2,371	)	$	(242	)		880	$	(34,996	)	$	(491	)		-

Segmented Results of Operations – Peru

Due to the significance of losses before income taxes, Peru became a significant reportable segment in 2011. The comparative amounts for 2010 were disaggregated from the Corporate Segment for presentation purposes.

DD&A expense for the six months ended June 30, 2011, includes a $33.4 million ceiling test impairment related to seismic and dry hole drilling costs.

The increase in G&A expense for both comparative periods resulted from expanded operations and the allocation of stock-based compensation to this business segment.

Capital Program – Peru

Capital expenditures for the three months ended June 30, 2011 were $11.3 million bringing the total expenditures in the region for the first six months of 2011 to $25.6 million, mainly related to the drilling of Kanatari -1 on Block 128, G&G expenditures in Block 122 and the acquisition of working interests in Blocks 123, 124 and 129. Capital expenditures for the three months ended June 30, 2010, were $1.6 million ($2.1 million for the six months ended June 30, 2010), mainly related to the acquisition of seismic data and commencement of drilling of Kanatari -1 on Block 128. The significant elements of Gran Tierra’s 2011 Capital Program in Peru are summarized below:

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·	Kanatari Prospect, Block 128 , Marañon Basin (100% working interest and Operator)

The Kanatari-1 exploration well reached total depth on March 3, 2011. No oil or gas shows were noted during drilling and interpretations from wireline logs indicate the reservoirs are water bearing. As a result, Kanatari-1 was plugged and abandoned; however, evaluation of the prospectivity of the block continues.

·	Block 122, Marañon Basin (100% working interest and Operator)

The prospectivity of Block 122 is under review as a result of the Kanatari-1 drilling result on the adjacent Block 128. No well will be drilled on the block in 2011 as currently permitted drilling locations are not prospective.

·	Blocks 123, 124 and 129, Marañon Basin (20% non-operated working interest)

In September 2010, Gran Tierra acquired a 20% non-operated working interest in ConocoPhillips operated Blocks 123, 124 and 129, subject to government approval. The approval for these blocks was granted on March 19, 2011 with final assignment completed April 26, 2011. Gran Tierra Energy is evaluating the prospectivity of these blocks based on recently acquired 2D seismic data.

Outlook - Peru

The 2011 capital program in Peru is $51 million with $21 million allocated to drilling, facilities and pipelines and $30 million to G&G expenditures.

Gran Tierra acquired three blocks on the Petrolifera acquisition: Blocks 106, 107 and 133. Prior to close of the acquisition, Petrolifera, in consultation with Gran Tierra, notified PeruPetro of the intention not to proceed to the next exploration phase in Block 106. Accordingly, the license agreement was terminated in April 2011.

Permitting for drilling on Block 107 in the Marañon Basin is advancing, with drilling expected to begin in the second half of 2012. The prospects on Block 107 are on trend with the world class gas-condensate discoveries that have been made around the Camisea region in southern Peru. Both oil and gas seeps are present on Block 107.

A drilling site location has been identified for the first exploration well on Block 95, in the Marañon Basin, with civil construction expected to begin in the third quarter of 2011. Drilling is expected to begin in second quarter of 2012. An oil field has already been discovered on Block 95, with the discovery well drilled in 1974 flowing 807 barrels of oil per day naturally without pumps. The new exploration well will further delineate this field and will explore deeper reservoir horizons not penetrated by the discovery well.

REVIEW OF CORPORATE SEGMENT AND OPERATIONS IN BRAZIL

	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			% Change			2011			2010			% Change
Segmented Results of Operations - Corporate
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	334		$	-			-		$	334		$	-			-
Interest		136			252			(46	)		272			337			(19	)
		470			252			87			606			337			80

Operating expenses		66			69			(4	)		66			87			(24	)
Depletion, depreciation and accretion		321			93			245			562			155			263
General and administrative expenses		7,205			4,809			50			16,047			8,003			101
Financial instruments gain		(1,292	)		-			-			(1,522	)		(44	)		-
Loss (gain) on acquisition		2,601			-			-			(21,699	)		-			-
Foreign exchange loss		268			795			66			273			375			27

		9,169			5,766			59			(6,273	)		8,576			(173	)

Segment income (loss) before income taxes	$	(8,699	)	$	(5,514	)		58		$	6,879		$	(8,239	)		(183	)

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Segmented Results of Operations – Corporate and Brazil

In addition to the expenditures associated with the maintenance of Gran Tierra’s headquarters in Calgary, Alberta, Canada, and cost of technical review, business development and compliance and reporting under securities regulations, the results of the Corporate Segment include the results of our initial operations in Brazil.

Oil and natural gas sales represent sales from Block 155 in the onshore Reconcavo Basin of Brazil subsequent to the receipt of the regulatory approval for the purchase of a 70% participating interest in that Block effective June 15, 2011.

The increase in G&A expenses between both comparative periods in the prior year was attributable to increased staff to manage expanded operations in all countries as well as the related higher stock-based compensation and $1.2 million incurred related to the acquisition of Petrolifera.

Financial instruments gain represents the change in the fair value of warrants issued in connection with the acquisition of Petrolifera.

The gain on acquisition relates to the gain recorded on the acquisition of Petrolifera (Note 3 to the condensed consolidated financial statements). The gain reflects the impact on Petrolifera’s pre-acquisition market value resulting from their lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects. Subsequent to the initial allocation of the consideration reported in the first quarter of 2011, further assessment of Petrolifera’s tax position resulted in a reduction of the gain on acquisition to $21.7 million from $24.3 million previously reported.

The foreign exchange loss results from the translation of foreign currency denominated transactions to U.S. dollars.

Capital Program – Corporate and Brazil

The capital expenditures for the Corporate Segment of $28.8 million and $29.8 million during the three and six month periods ended June 30, 2011, respectively, related primarily to the acquisition of a 70% participating working interest in Blocks 129, 142, 155 and 224 in the onshore Reconcavo Basin of Brazil. Expenditures in the comparative periods of 2010 of $0.5 million and $1.3 million, respectively, related to leasehold improvements and purchase of office furniture and equipment for Gran Tierra’s headquarters in Calgary and Brazil. The significant elements of Gran Tierra’s 2011 Capital Program in Brazil are summarized below:

·	Blocks 129, 142, 155, and 224 (70% working interest and Operator)

In August 2010, Gran Tierra established an initial exploration and production position in Brazil, subject to approval by Agência Nacional de Petróleo Gás Natural e Biocombustíveis (“ANP”), whereby Gran Tierra will receive a 70% working interest in four blocks in the onshore Recôncavo Basin. In June 2011, Gran Tierra received final approvals for Blocks 129, 142 and 224 and 155 and assumed its working interest share of a light oil discovery.

Outlook - Brazil

The 2011 capital program in Brazil is $62 million and includes $23 million budgeted for drilling and completions and the remainder for facilities, geophysical and acquisition costs of Gran Tierra’s 70% working interest in the four blocks described above.

Gran Tierra expects to drill two gross development wells in 2011 to grow production from the Block 155, which is currently producing 500 barrels of oil per day gross from one zone without the assistance of pumps.

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In addition, two exploration wells are planned for 2011, one well on Block 129 and one well on Block 142. Drilling rigs are currently being tendered and locations are being permitted. The first exploration well is expected to spud on Block 142 at the end of third quarter of 2011.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2011, we had cash and cash equivalents of $211.4 million compared to $355.4 million at December 31, 2010. The bank debt of $31.3 million reflected in the condensed consolidated balance sheet as at June 30, 2011, represents the reserve backed credit facility acquired as part of the Petrolifera acquisition as described below. The outstanding balance was repaid when the Argentine restriction preventing its repayment expired on August 5, 2011. We are debt free at that time. We believe that our cash position and cash generated from operations will provide us with sufficient liquidity to meet our strategic objectives and fund the debt repayment and our planned capital program for at least the next 12 months. In accordance with our investment policy, cash balances are invested only in high quality bank paper at overnight or short term rates, and in United States or Canadian government backed federal, provincial or state securities with the highest credit ratings and short term liquidity.

Effective July 30, 2010, Gran Tierra 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 of up to $100 million and is supported by the present value of our Colombian petroleum reserves. The initial committed borrowing base is $20 million. Amounts drawn down under the facility bear interest at the U.S. dollar 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 expenses. Under the terms of the facility, we are required to maintain and were in compliance with certain financial and operating covenants. As at June 30, 2011, we had not drawn down any amounts under this facility.

As part of the acquisition of Petrolifera on March 18, 2011, we assumed a $100.0 million reserve backed credit facility with available and outstanding balance as at the Acquisition Date and June 30, 2011 of $31.1 million. This credit facility agreement with a syndicate of banks expires on June 30, 2012. The credit facility bears interest at LIBOR plus 8.25%, is partially secured by the pledge of the shares of Petrolifera's subsidiaries and has a provision for a borrowing base adjustment every six months. Under the terms of the facility, we are required to maintain and were in compliance with certain financial and operating covenants. We have classified this credit facility as current at June 30, 2011 and repaid the credit facility on August 5, 2011. A regulation of the Argentine Central Bank established that "new indebtedness and renewals of debts with foreign creditors engaged by local residents shall be kept for a minimum of 365 days". Petrolifera entered into an amendment of this credit facility on August 4, 2010, which then renewed and restructured the existing debt. As a result, the principal debt that was loaned into Argentina could not be repaid and retired until August 2011.

Cash Flows

During the six months ended June 30, 2011, our cash and cash equivalents decreased by $144.1 million as net cash provided by operating activities was more than offset by our capital expenditures.

Net cash provided by operating activities was positively affected by increasing productions levels and improved crude oil prices. These positive contributions were partially offset by increased operating and G&A expenses to support the expanded operations and a significant increase in accounts receivable which was mainly attributable to the timing of payments from Ecopetrol.

Cash outflows from investing activities included cash capital expenditures of $179.2 million and an increase in restricted cash of $8.1 million offset by proceeds on sale of ABCP of $22.7 million and $7.7 million cash acquired through the Petrolifera acquisition.

Financing activities included the repayment of $22.9 million of debt acquired through the Petrolifera acquisition, offset partially by $2.5 million related to proceeds from issuance of common shares.

During the six months ended June 30, 2010, our cash and cash equivalents increased $22.4 million as cash inflows from operations of $53.0 million and proceeds from issuance of common shares of $18.5 million more than offset cash outflows for capital expenditures of $50.9 million. Net cash provided by operating activities was positively affected by the increases in crude oil production and prices, offset by higher receivables related to oil sales.

OFF-BALANCE SHEET ARRANGEMENTS

As at June 30, 2011, we had no off-balance sheet arrangements.

CONTRACTUAL OBLIGATIONS

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Gran Tierra holds four categories of operating leases, namely compressor office, vehicle and equipment and housing. Future lease payments and other contractual obligations at June 30, 2011 are as follows:

	As at June 30, 2011
	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	$	10,703	$	5,584	$	4,311	$	808	$	-
Bank debt		31,250		31,250		-		-		-
Software and telecommunication		3,072		1,858		1,032		182		-
Drilling, completion, facility construction and oil transportation services		103,543		71,853		22,069		9,621		-
Consulting		806		806		-		-		-
Total	$	149,374	$	111,351	$	27,412	$	10,611	$	-

Contractual commitments have increased $70.7 million from December 31, 2010 mainly as a result of bank debt and compressor and other operating equipment leases assumed upon the acquisition of Petrolifera as previously discussed.

RELATED PARTY TRANSACTIONS

On February 1, 2009, we entered into a sublease for office space with a company, of which one of Gran Tierra’s directors is a shareholder and director. The term of the sublease runs from February 1, 2009 to August 31, 2011 and the sublease payment is $8,800 per month plus approximately $4,500 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, we entered into a contract related to the Peru drilling program with a company of which one of our directors is a shareholder and director. For the six months ended June 30, 2011, $2.2 million was capitalized and at June 30, 2011, $0.1 million was included in accounts payable related to this contract, the terms of which are consistent with market conditions.

On January 12, 2011, we entered into an agreement to sublease office space to a company of which our President and Chief Executive Officer serves as an independent director. The term of the sublease runs from February 1, 2011 to January 30, 2013 and, at $4,400 per month plus approximately $5,700 for operating and other expenses, the terms are consistent with market conditions in the Calgary, Alberta, Canada real estate market.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements under generally accepted accounting principles (“GAAP”) in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

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

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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 policies and estimates are disclosed in Item 7 of our 2010 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 25, 2011, and have not changed materially since the filing of that document.

ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our principal market risk relates to oil prices. Essentially 100% of our revenues are from oil sales at prices which are defined by contract relative to WTI and adjusted for transportation and quality for each month. In Argentina, a further discount factor which is related to a tax on oil exports establishes a common pricing mechanism for all oil produced in the country, regardless of its destination.

We consider our exposure to interest rate risk to be immaterial. Interest rate exposures relate primarily to our investment portfolio as the $31.3 million debt under our reserve backed credit facility, which is based on LIBOR plus 8.25 %, was repaid on August 5, 2011 when the Argentine restrictions preventing us from doing so lapsed. 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 issues at overnight rates, or government securities of the United States or Canadian federal governments such as Guaranteed Investment Certificates or Treasury Bills. We do not hold any of these investments for trading purposes. We do not hold equity investments.

Foreign currency risk is a factor for our company but is ameliorated to a large degree by the nature of expenditures and revenues in the countries where we operate. We have not engaged in any formal hedging activity with regard to foreign currency risk. Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. price of West Texas Intermediate oil. In Colombia, we receive 100% of our revenues in U.S. dollars. The majority of our capital expenditures in Colombia are in U.S. dollars and the majority of local office costs are in local currency. In Argentina, reference prices for oil are in U.S. dollars and revenues are received in Argentine pesos according to current exchange rates. The majority of capital expenditures within Argentina have been in U.S. dollars with local office costs generally in pesos. The majority of our capital expenditures in Brazil and Peru are in U.S. dollars and the majority of local office costs are in the local currencies. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

Additionally, foreign exchange gains/losses result from the fluctuation of the U.S. dollar to the Colombian peso due to our deferred tax liability, a monetary liability, which is mainly denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain/loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $110,000 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 June 30, 2011 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

We acquired Petrolifera Petroleum Limited on March 18, 2011 and are currently in the process of integrating it into our existing internal controls and procedures. There were no changes in our internal control over financial reporting during the quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

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, 2010, filed with the Securities and Exchange Commission on February 25, 2011, are set forth below and are unchanged substantively at June 30, 2011, other than those designated by an asterisk “*”.

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 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 or displaced by Ecopetrol’s use of the pipeline itself. 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 with 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, again in June, August, and September 2010, and again in February 2011 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 us, our employees and the public.

As some of our 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.

Over the years, our profile in Columbia has increased which creates a greater risk for us and our employees to be targeted by guerilla or other criminal groups. Despite significant recent security gains, Colombia remains a country where safety is a significant concern. For over 40 years, the government has been engaged in a civil war with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia (FARC) and the National Liberation Army (ELN). Both of these groups have been designated as terrorist organizations by the United States and the European Union. In recent years, however, the government has successfully dissolved the AUC militia, a paramilitary group that originally sprouted up to combat the FARC and ELN. The dissolved AUC militia members have reorganized in the form of criminal gangs.

We operate principally in the Putumayo basin in Colombia, and have properties in other basins, including the Catatumbo, Llanos, Middle Magdalena and Lower Magdalena basins. The Putumayo and Catatumbo regions have been prone to guerilla activity. In 1989, our predecessor company’s facilities in one field were attacked by guerillas and operations were briefly disrupted. Again on 16 October 2010, two of our sites in the Putumayo/Cauca were attacked by FARC guerillas causing some disruption to operations. Pipelines have also been targets, including the Ecopetrol - operated Trans Andean (OTA) 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, again in June, August, and September 2010, and again in February 2011, sections of the Trans Andean pipeline were sabotaged by guerillas, which temporarily reduced our deliveries to Ecopetrol during the affected periods.

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Continuing attempts by the Colombian Government 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 field and Bogota head office personnel or operations in Colombia or that this violence will not affect our operations in the future and cause significant loss.

*We Have an Aggressive Business Plan, and if we do not Have the Resources to Execute on our Business Plan, We May Be Required to Curtail Our Operations.

Our capital program for 2011 calls for approximately $357 million to fund our exploration and development, which we intend to fund through existing cash and cash flows from operations. Funding this program relies in part on oil prices remaining high and other factors to generate sufficient cash flow. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our business plan which would cause us to decrease our exploration and development, which could harm our business outlook, investor confidence and our share price.

*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 our business. 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 are experiencing difficulties in finding and retaining suitably qualified staff in certain jurisdictions, particularly in Brazil, Argentina, Peru and Calgary, where experienced personnel in our industry are in high demand and competition for their talents is intense.

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 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 us 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 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 four customers. The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results. Currently all operators in Argentina are operating without long term sales contracts. We cannot provide any certainty as to when the situation will be resolved or what the final outcome will be.

*Strategic and Business 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 our 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 and business 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 also have an active business development program to develop those relationships. We may not be able to establish these business 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 us.

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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. Starting in 2010, there was an increased presence of illegitimate unionization activities in the Putumayo Basin by the Sindicato de Trabajadores Petroleros del Putumayo , which disrupted our operations from time to time and may do so in the future. During 2011, Argentina has experienced increased union activity and this may create disruptions in our Argentinian operations 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.

*Disputes or Uncertainties May Arise in Relation to our Royalty Obligations

Our production is subject to royalty obligations which may be prescribed by government regulation or by contract. These royalty obligations may be subject to changes in interpretation as business circumstances change.

In accordance with our Hydrocarbon Exploration and Exploitation Agreement with Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) for the Chaza Block in Colombia our crude oil production from each Exploitation Area on the Block is subject to the payment of additional compensation to the ANH over and above the basic sliding scale royalty that applies when cumulative gross production from an Exploitation Area exceeds five million barrels. Production from the Costayaco Exploitation Area on the Chaza Block became subject to this additional compensation in the fourth quarter of 2009 after cumulative production from the Costayaco field exceeded five million barrels.

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The ANH has requested that the additional compensation be paid with respect to production from the recently drilled wells relating to the Moqueta discovery and has initiated a non-compliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, we view the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is our view that it is clear that pursuant to the Chaza Contract the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated crude oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. At the end of the first quarter of 2011, cumulative production from the Moqueta field consists of a small amount of test production only. We will respond to the ANH in accordance with the provisions of the Chaza Contract. However, no assurance can be made that our interpretation will prevail and depending on the ultimate size of the cumulative production from the Moqueta field in the future, such amounts may be material if such additional compensation must be paid.

In Brazil, a new regulatory regime was introduced, however, the royalty distribution between producing states has not been approved.

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 in Argentina is primarily invoiced in United States dollars, but payment is made in Argentine 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 functional currency. Since we began operating in Argentina (September 1, 2005), the rate of exchange between the Argentine peso and U.S. dollar has varied between 3.05 pesos to one U.S. dollar to 4.35 pesos to the U.S. dollar, a fluctuation of approximately 43%. Exchange rates between the Colombian peso and U.S. dollar have varied between 2,632 pesos to one U.S. dollar to 1,648 pesos to one U.S. dollar since September 1, 2005, a fluctuation of approximately 60%.

In addition, a foreign exchange loss of $19.1 million, of which $16.1 million is an unrealized non-cash foreign exchange loss, was recorded for the six months ended June 30, 2011 and was 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 7% in the U.S. dollar against the Colombian Peso in the 6 month period ended June 30, 2011 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.

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*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.

Further, we operate in remote areas and may rely on helicopter or other transport methods. Some of these transport methods may result in increased levels of risk and could lead to operational delays, serious injury or loss of life and have a significant impact on our reputation.

*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.

In October 2010, ENARGAS issued Regulation I-1410 aiming at securing the supply of natural gas to residential consumers and small industry given the decline in gas production and the expected growing demand for gas. The regulation includes all the procedures created by the authorities since 2004 (restrictions of exports, deviation of gas sales, to residential consumption) and gives ENARGAS power to control gas marketing in order to assure the supply of gas to residential consumers and small industry.

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, Refineria del Norte S.A, and the price is negotiated on a month by month basis. As a result of our acquisition of Petrolifera, we are now also selling our crude oil through short term contracts to Shell Compania Argentina de Petroleo S.A. and YPF S.A. and natural gas to Rafael G. Albenesi S.A. 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 Refineria del Norte 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.

A presidential election is scheduled to be held in Argentina during October 2011 and a newly resulting political regime may adopt new policies, laws and regulations that are more hostile towards foreign investment which may result in the imposition of additional taxes, the adoption of regulation that limits price increases, termination of contract rights, or the expropriation of foreign-owned assets.

*Negative Political Developments in Peru May Negatively Affect our Proposed Operations.

Peru held a national election in June 2011 after which a new political regime was elected, led by the left-populist candidate, Ollante Humala, who was elected the president. Mr. Humala has noted that the past decade prioritized the strengthening of democracy with economic growth, while the new government will enhance social inclusion to benefit the neediest. This newly elected political regime may adopt new policies, laws and regulations that are more hostile toward foreign investment which may result in the imposition of additional taxes, the adoption of regulations that limit price increases, termination of contract rights, or the expropriation of foreign-owned assets. While we do not have any reserves or any producing wells in Peru at this point, we do hold significant land holdings in Peru and such actions by the newly elected political regime could limit the amount of our future revenue in that country and affect our results of operations.

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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 shareholders, 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 curtail 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. In particular, on March 18, 2011, we acquired Petrolifera (through a plan of arrangement), a company with substantial assets featuring both high working interest and operatorship in three of the four South American countries in which we operate. For the acquisition to be successful, we must be successful at retaining key employees, integrating Petrolifera’s operations and developing Petrolifera’s reserves. Such integration efforts place a significant burden on our management and internal resources. The diversion of management attention and any difficulties encountered in the integration process could harm our business, financial condition and results of operations. In addition, 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:

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·	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 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 technical conditions. While we will endeavor to effectively manage these conditions, we may not be able to do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We are Required to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain These Licenses Could Cause Significant Delays and Expenses That Could Materially Impact Our Business.

We are subject to licensing and permitting requirements relating to exploring and drilling for and development of oil and natural gas, including seismic permits. We may not be able to obtain, sustain or renew such licenses and permits 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.

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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. In 2010, we recorded a ceiling test impairment loss of $23.6 million in our Argentina cost center. In counties where we do not have proved reserves, dry wells drilled in a period would directly result in a ceiling test impairment for that period. In the six months ended June 30, 2011, we recorded a ceiling test impairment loss of $33.4 million in our Peru cost center related to our exploration projects.

*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 GTE.St.VMor-2001 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. The operation was placed on standby pending the arrival of additional side-track equipment and operations recommenced in fourth quarter of 2010. In February 2011, these operations were suspended and the wellbore has been abandoned due to a number of operational challenges encountered. We continue to review alternatives associated with the field development. 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.

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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 Our Profitability, Growth and Value.

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 per barrel was $66 in 2006, $72 in 2007, $100 in 2008, $62 in 2009, $79 in 2010 and $98 for the six months ended June 30, 2011 demonstrating the inherent volatility in the market. Given the current economic environment and unstable conditions in the Middle East, Libya and the United States, the oil price environment is increasingly unpredictable and unstable. 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 differentials. 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, 2010 and 2011 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.

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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, blowouts, 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 acquisitions of other companies or assets;

●	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.

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

●	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 us, 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.

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 shareholders 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 8 separate dates beginning on April 1, 2011 and ending on June 30, 2011, we issued an aggregate of 525,817 shares of our common stock for an aggregate purchase price of $552,108. These shares were issued to 10 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.

ITEM 5. OTHER INFORMATION

The Board of Directors of Gran Tierra Energy Inc. amended the Gran Tierra Energy Inc. 2007 Equity Incentive Plan to provide that in the event of a “corporate transaction” the equity awards granted under the plan will vest in their entirety. Prior to the amendment to the plan, the equity awards would vest in the event of a “corporate transaction” only if the equity awards were not assumed, continued or substituted. The amendment is subject to Toronto Stock Exchange confirmation that stockholder approval is not required.

A “corporate transaction” is: a sale or other disposition of all or substantially all of Gran Tierra’s assets; a sale or other disposition of at least 50% of the outstanding Gran Tierra securities; a merger, consolidation or similar transaction following which Gran Tierra is not the surviving corporation; or a merger, consolidation or similar transaction following which Gran Tierra is the surviving corporation but the shares of common stock outstanding immediately preceding the merger, consolidation or similar transaction are converted or exchanged by virtue of the merger, consolidation or similar transaction into other property, whether in the form of securities, cash or otherwise.

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: August 9, 2011	/s/ Dana Coffield
	By: Dana Coffield
Its: Chief Executive Officer

Date: August 9, 2011	/s/ Martin Eden
	By: Martin Eden
Its: Chief Financial Officer

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EXHIBIT INDEX

Exhibit

No.	Description	Reference

2.1	Arrangement Agreement, dated as of July 28, 2008, by and among Gran Tierra Energy Inc., Solana Resources Limited and Gran Tierra Exchangeco Inc.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (SEC File No. 001-34018), filed with the SEC on August 1, 2008.

2.2	Amendment No. 2 to Arrangement Agreement, which supersedes Amendment No. 1 thereto and includes the Plan of Arrangement, including appendices	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-3 (SEC File No. 333-153376), filed with the SEC on October 10, 2008.

2.3	Arrangement Agreement, dated January 17, 2011, by and between Gran Tierra Energy Inc. and Petrolifera Petroleum Limited.#	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on January 21, 2011 (SEC File No. 001-34018).

3.1	Amended and Restated Articles of Incorporation.	Incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A (SEC File 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 (SEC File No. 000-52594).

4.1	Reference is made to Exhibits 3.1 to 3.2.

4.2	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 (SEC File No. 333-111656).

4.3	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 (SEC File No. 333-111656).

4.4	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 (SEC File No. 333-111656).

4.5	Provisions Attaching to the GTE–Solana Exchangeable Shares.	Incorporated by reference to Annex E to the Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on October 14, 2008 (SEC File No. 001-34018).

4.6	Supplemental Warrant Indenture, dated as of March 18, 2011, among Gran Tierra Energy Inc., Petrolifera Petroleum Limited, and Computershare Trust Company of Canada.	Incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q (SEC File No. 001-34018), filed with the SEC on May 10, 2011.

10.1	Addendum No. 2, entered into between Gran Tierra Colombia Ltd. and Ecopetrol S.A. on December 30, 2010, amending the Agreement between those parties dated December 17, 2009 and accepted December 18, 2009, with respect to the sale of crude oil from the Chaza Block.	Filed herewith.

10.2	Addendum No. 2, entered into between Solana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A. on June 30, 2011, amending the Agreement between those parties dated December 17, 2009 and accepted December 18, 2009, with respect to the sale of crude oil from the Chaza Block.	Filed herewith.

10.3	Contract, dated July 27, 2011, between Gran Tierra Colombia Ltd. and Ecopetrol S.A., for the Purchase and Sale of Crude Oil from the Chaza, Santana and Guayuyaco Blocks.	Filed herewith.

10.4	Contract, dated July 27, 2011, between Solana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A., for the Purchase and Sale of Crude Oil from the Chaza, Santana and Guayuyaco Blocks.	Filed herewith.

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31.1	Certification of Principal Executive Officer	Filed herewith.

31.2	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

# Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Gran Tierra undertakes to furnish supplemental copies of any of the omitted schedules upon request by the Securities and Exchange Commission.

* 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.

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Part I - Financial Information Item 1 - Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3 - Quantitative and Qualitative Disclosures About Market Risk Item 4. - Controls and Procedures Part II - Other Information Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 5. Other Information Item 6. Exhibits

Exhibits

10.1 Addendum No. 2, entered into between Gran Tierra Colombia Ltd. and Ecopetrol S.A. on December 30, 2010, amending the Agreement between those parties dated December 17, 2009 and accepted December 18, 2009, with respect to the sale of crude oil from the Chaza Block. Filed herewith. 10.2 Addendum No. 2, entered into betweenSolana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A. on June 30, 2011, amending the Agreement between those parties dated December 17, 2009 and accepted December 18, 2009, with respect to the sale of crude oil from the Chaza Block. Filed herewith. 10.3 Contract, dated July 27, 2011, between Gran Tierra Colombia Ltd. and Ecopetrol S.A., for the Purchase and Sale of Crude Oil from the Chaza, Santana and Guayuyaco Blocks. Filed herewith. 10.4 Contract, dated July 27, 2011, between Solana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A., for the Purchase and Sale of Crude Oil from the Chaza, Santana and Guayuyaco Blocks. Filed herewith. 31.1 Certification of Principal Executive Officer Filed herewith. 31.2 Certification of Principal Financial Officer Filed herewith. 32.1 Section 1350 Certifications. Filed herewith.

GTE 10-Q Quarter ended June 30, 2011

Exhibits