GTE 10-Q Quarterly Report Sept. 30, 2011

GRAN TIERRA ENERGY INC.

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on May 2, 2025
DEF 14A	Filed on March 18, 2025
DEF 14A	Filed on May 2, 2024
DEF 14A	Filed on March 21, 2024
DEF 14A	Filed on March 24, 2023
DEF 14A	Filed on May 4, 2022
DEF 14A	Filed on March 25, 2022
DEF 14A	Filed on March 25, 2021
DEF 14A	Filed on March 25, 2020
DEF 14A	Filed on March 26, 2019
DEF 14A	Filed on March 21, 2018
DEF 14A	Filed on March 20, 2017
DEF 14A	Filed on April 29, 2016
DEF 14A	Filed on May 15, 2015
DEF 14A	Filed on April 30, 2014
DEF 14A	Filed on April 30, 2013
DEF 14A	Filed on April 30, 2012
DEF 14A	Filed on May 2, 2011
DEF 14A	Filed on April 30, 2010

10-Q 1 form10q.htm GRAN TIERRA ENERGY INC 10-Q 9-30-2011 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 September 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 11th Avenue S.W. Calgary, Alberta, Canada		T2R 0E1
(Address of principal executive offices)		(Zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

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 November 1, 2011, the following numbers of shares of the registrant’s capital stock were outstanding: 261,161,809 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 8,655,980 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

TABLE OF CONTE NT S

		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	39

ITEM 4.	CONTROLS AND PROCEDURES	39

PART II - OTHER INFORMATION

ITEM 1A.	RISK FACTORS	40

ITEM 6.	EXHIBITS	50

SIGNATURES		51

EXHIBIT INDEX		52

Table Of Contents

PART I - FINANCIAL INFORMATION

ITEM 1 - FINANCIAL ST ATE MENTS

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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

REVENUE AND OTHER INCOME
Oil and natural gas sales	$	150,824		$	84,110		$	434,784		$	260,759
Interest		209			459			888			1,034
		151,033			84,569			435,672			261,793
EXPENSES
Operating		21,727			19,401			61,283			39,028
Depletion, depreciation, accretion and impairment (Note 5)		49,852			35,254			160,174			107,238
General and administrative		16,316			10,977			46,364			27,848
Equity tax (Note 8)		-			-			8,271			-
Financial instruments gain (Note 3)		-			-			(1,522	)		(44	)
Gain on acquisition (Note 3)		-			-			(21,699	)		-
Foreign exchange (gain) loss		(15,921	)		16,320			3,773			33,740
		71,974			81,952			256,644			207,810

INCOME BEFORE INCOME TAXES		79,059			2,617			179,028			53,983
Income tax expense (Note 8)		(29,974	)		(5,894	)		(84,663	)		(29,929	)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)		49,085			(3,277	)		94,365			24,054
RETAINED EARNINGS, BEGINNING OF PERIOD		103,377			48,256			58,097			20,925
RETAINED EARNINGS, END OF PERIOD	$	152,462		$	44,979		$	152,462		$	44,979

NET INCOME (LOSS) PER SHARE — BASIC	$	0.18		$	(0.01	)	$	0.35		$	0.10
NET INCOME (LOSS) PER SHARE — DILUTED	$	0.17		$	(0.01	)	$	0.34		$	0.09
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)		277,608,572			254,951,642			272,006,775			252,487,462
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)		284,026,236			254,951,642			279,485,895			260,294,503

(See notes to the condensed consolidated financial statements)

Table Of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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

	September 30,		December 31,
	2011		2010

ASSETS
Current Assets
Cash and cash equivalents	$	226,370	$	355,428
Restricted cash (Note 11)		2,990		250
Accounts receivable		143,533		43,035
Inventory (Note 2)		6,334		5,669
Taxes receivable		21,200		6,974
Prepaids		2,051		1,940
Deferred tax assets (Note 8)		2,504		4,852

Total Current Assets		404,982		418,148

Oil and Gas Properties (using the full cost method of accounting)
Proved		579,212		442,404
Unproved		430,870		278,753

Total Oil and Gas Properties		1,010,082		721,157

Other capital assets		7,325		5,867

Total Property, Plant and Equipment (Note 5)		1,017,407		727,024

Other Long Term Assets
Restricted cash (Note 11)		1,435		1,190
Deferred tax assets (Note 8)		13,100		-
Other long term assets		250		311
Goodwill		102,581		102,581

Total Other Long Term Assets		117,366		104,082

Total Assets	$	1,539,755	$	1,249,254

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	41,394	$	76,023
Accrued liabilities		63,296		32,120
Taxes payable		69,427		43,832
Asset retirement obligations (Note 7)		357		338

Total Current Liabilities		174,474		152,313

Long Term Liabilities
Deferred tax liabilities (Note 8)		211,245		204,570
Equity tax payable (Note 8)		6,783		-
Asset retirement obligations (Note 7)		10,787		4,469
Other long term liabilities		955		1,036

Total Long Term Liabilities		229,770		210,075

Commitments and Contingencies (Note 9)

Shareholders’ Equity
Common shares (Note 6) (261,053,809 and 240,440,830 common shares and 16,575,092 and 17,681,123 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2011 and December 31, 2010, respectively)		5,971		4,797
Additional paid in capital		975,298		821,781
Warrants (Note 6)		1,780		2,191
Retained earnings		152,462		58,097

Total Shareholders’ Equity		1,135,511		886,866

Total Liabilities and Shareholders’ Equity	$	1,539,755	$	1,249,254

(See notes to the condensed consolidated financial statements)

Table Of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Nine Months Ended September 30,
	2011				2010

Operating Activities
Net income		$	94,365			$	24,054
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, accretion and impairment			160,174				107,238
Deferred taxes (Note 8)			(15,488	)			(28,026	)
Stock-based compensation (Note 6)			9,383				5,424
Unrealized gain on financial instruments (Note 3)			(1,354	)			(44	)
Unrealized foreign exchange loss			136				27,136
Settlement of asset retirement obligations (Note 7)			(309	)			(263	)
Equity taxes			2,741				-
Gain on acquisition (Note 3)			(21,699	)			-
Net changes in non-cash working capital
Accounts receivable			(90,014	)			(35,195	)
Inventory			4				1
Prepaids			224				10
Accounts payable and accrued liabilities			(7,287	)			(8,402	)
Taxes receivable and payable			9,658				9,455

Net cash provided by operating activities			140,534				101,388

Investing Activities
Restricted cash			260				656
Additions to property, plant and equipment			(248,820	)			(88,954	)
Proceeds from disposition of oil and gas property			-				1,600
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			63				28

Net cash used in investing activities			(218,071	)			(86,670	)

Financing Activities
Settlement of bank debt (Notes 3 and 11)			(54,103	)			-
Proceeds from issuance of common shares			2,582				22,892

Net cash (used in) provided by financing activities			(51,521	)			22,892

Net (decrease) increase in cash and cash equivalents			(129,058	)			37,610
Cash and cash equivalents, beginning of period			355,428				270,786

Cash and cash equivalents, end of period		$	226,370			$	308,396

Cash		$	84,146			$	223,320
Term deposits			142,224				85,076
Cash and cash equivalents, end of period		$	226,370			$	308,396

Supplemental cash flow disclosures:
Cash paid for interest		$	1,604			$	-
Cash paid for income taxes		$	64,310			$	42,024
Non-cash investing activities:
Non-cash working capital related to property, plant and equipment		$	26,423			$	30,747

(See notes to the condensed consolidated financial statements)

Table Of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Nine Months Ended				Year Ended
	September 30, 2011				December 31, 2010

Share Capital
Balance, beginning of period		$	4,797			$	1,431
Issue of common shares			1,174				3,366

Balance, end of period			5,971				4,797


Additional Paid in Capital
Balance, beginning of period			821,781				766,963
Issue of common shares			142,109				19,119
Exercise of warrants (Note 6)			411				24,916
Exercise of stock options (Note 6)			987				2,300
Stock-based compensation expense (Note 6)			10,010				8,483

Balance, end of period			975,298				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			94,365				37,172

Balance, end of period			152,462				58,097

Total Shareholders’ Equity		$	1,135,511			$	886,866

(See notes to the condensed consolidated financial statements)

Table Of Contents

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 information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

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). The Replacement Warrants expired unexercised during August 2011. These warrants were derivative financial instruments and were recognized at fair value in the consolidated balance sheet as a current liability and as part of the consideration paid for the acquisition . The fair value of the Replacement Warrants was determined using the Black-Scholes option pricing model and changes therein were recognized in net income when the changes occurred. The Company does not use derivative financial instruments for speculative purposes.

Inventory

Crude oil inventories at September 30, 2011 and December 31, 2010 are $4.3 million and $3.6 million, respectively. Supplies at September 30, 2011 and December 31, 2010 are $2.0 million and $2.1 million.

Recently Issued Accounting Pronouncements

Goodwill

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”), "Intangibles – Goodwill and Other (Topic 350)." The update is intended to simplify how entities test goodwill for impairment. The update permits entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the two-step goodwill impairment test. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011. The Company does not expect to early adopt this standard. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, results of operations or cash flows.

Adopted Accounting Pronouncements

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 disclosure requirements of this ASU have been adopted by the Company.

Table Of Contents

Stock Compensation

In April 2010, the FASB issued 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, results of operations or cash flows.

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. The Replacement Warrants expired unexercised 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

The Replacement Warrants met the definition of a derivative. Because the exercise price of the Replacement Warrants was denominated in Canadian dollars, which is different from Gran Tierra’s functional currency, the Replacement Warrants were not considered indexed to Gran Tierra’s common shares and the Replacement Warrants could not be classified within equity. Therefore the Replacement Warrants were classified as a current liability on Gran Tierra’s condensed consolidated balance sheet. Furthermore, these derivative instruments did not qualify as fair value hedges or cash flow hedges, and accordingly, changes in their fair value were recognized as income or expense in the consolidated statement of operations and retained earnings with a corresponding adjustment to the fair value of derivative instruments recognized on the balance sheet. The financial instruments gain reflected in the consolidated statement of operations for the nine months ended September 30, 2011, includes a $1.3 million gain arising from the fair value of the expired Replacement Warrants.

The acquisition is accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed are recognized 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.

Table Of Contents

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 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 was 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. When combined with the gain arising on the expiry of the Replacement Warrants, the financial instruments gain for the nine months ended September 30, 2011 was $1.5 million.

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.

Table Of Contents

Gran Tierra also assumed a reserve-backed credit facility upon the Petrolifera acquisition with an outstanding balance of $31.3 million (Note 11). The amount outstanding under this credit facility was included as part of net working capital in the allocation of consideration transferred. This credit facility was repaid during August 2011, resulting in a total debt repayment of $54.1 million, when combined with the repayment of the CDN$22.5 million ABCP line of credit.

The pro forma results for the three months ended September 30, 2011 and the three and nine months ended September 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 September 30,			Nine Months Ended September 30,
(Thousands of U.S. Dollars except per share amounts)	2010			2011		2010
Revenue and other income	$	97,535		$	444,867	$	303,547
Net (loss) income	$	(5,546	)	$	61,542	$	25,994
Net (loss) income per share - basic	$	(0.02	)	$	0.23	$	0.10
Net (loss) income per share - diluted	$	(0.02	)	$	0.22	$	0.09

The supplemental pro forma earnings of Gran Tierra for the three and nine months ended September 30, 2011 were adjusted to exclude $4.4 million of acquisition costs recorded in general and administrative (“G&A”) 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 nine months ended September 30, 2011 includes oil and natural gas sales of $22.3 million from Petrolifera for the period subsequent to the Acquisition Date. Petrolifera incurred a loss after tax of $2.8 million in the period since the Acquisition Date.

4. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia, Argentina and Peru based on a geographic organization. The Company’s operations in Brazil are not a reportable segment because the level of activity in Brazil is not significant at this time. In the three months ended March 31, 2011, Peru became a reportable segment due to the significance of its loss before income taxes compared with the consolidated results of operations. Prior year segmented disclosure has been conformed to this presentation with the Peru related results and asset information disaggregated from the “All Other” category. The All Other category represents the Company’s corporate activities and operations in Brazil.

The accounting policies of the reportable 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 segments and other activities:

	Three Months Ended September 30, 2011
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia			Argentina				Peru			All Other				Total
Oil and natural gas sales		$	133,475		$	15,188		$	-			$	2,161			$	150,824
Interest income (expense)			130			(22	)		6				95				209
Depletion, depreciation, accretion and impairment			34,916			6,508			7,375				1,053				49,852
Depletion, depreciation, accretion and impairment - per unit of production			25.53			21.62			-				0.05				29.50
Segment income (loss) before income taxes			96,503			(1,623	)		(8,432	)			(7,389	)			79,059
Segment capital expenditures		$	40,100		$	7,100		$	4,096			$	7,268			$	58,564

Table Of Contents

	Three Months Ended September 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts)		Colombia			Argentina			Peru				All Other				Total
Oil and natural gas sales		$	80,731		$	3,379		$	-			$	-			$	84,110
Interest income			301			-			-				158				459
Depletion, depreciation, accretion and impairment			33,916			1,208			16				114				35,254
Depletion, depreciation, accretion and impairment - per unit of production			28.78			18.08			-				-				28.31
Segment income (loss) before income taxes			8,305			(405	)		(591	)			(4,692	)			2,617
Segment capital expenditures		$	22,084		$	12,289		$	7,080			$	6,233			$	47,686

	Nine Months Ended September 30, 2011
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia			Argentina				Peru			All Other				Total
Oil and natural gas sales		$	399,252		$	33,038		$	-			$	2,494			$	434,784
Interest income			375			6			140				367				888
Depletion, depreciation, accretion and impairment			104,560			13,161			40,838				1,615				160,174
Depletion, depreciation, accretion and impairment - per unit of production			26.33			20.12			-				0.06				34.45
Segment income (loss) before income taxes			228,118			(5,152	)		(43,428	)			(510	)			179,028
Segment capital expenditures		$	136,580		$	25,859		$	29,670			$	37,046			$	229,155

	Nine Months Ended September 30, 2010
(Thousands of U.S. Dollars except per unit of production amounts)		Colombia			Argentina			Peru				All Other				Total
Oil and natural gas sales		$	250,767		$	9,992		$	-			$	-			$	260,759
Interest income			520			19			-				495				1,034
Depletion, depreciation, accretion and impairment			99,243			7,699			27				269				107,238
Depletion, depreciation, accretion and impairment - per unit of production			27.57			36.96			-				-				28.16
Segment income (loss) before income taxes			74,154			(6,158	)		(1,082	)			(12,931	)			53,983
Segment capital expenditures		$	68,531		$	16,763		$	9,216			$	7,536			$	102,046

	As at September 30, 2011
(Thousands of U.S. Dollars)	Colombia			Argentina				Peru			All Other				Total
Property, plant and equipment		$	786,783		$	151,156		$	28,948			$	50,520			$	1,017,407
Goodwill			102,581			-			-				-				102,581
Other assets			255,399			36,766			8,384				119,218				419,767
Total Assets		$	1,144,763		$	187,922		$	37,332			$	169,738			$	1,539,755

Table Of Contents

	As at December 31, 2010
(Thousands of U.S. Dollars)		Colombia		Argentina		Peru		All Other		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 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 87% of the Company’s oil and natural gas sales for the three and nine months ended September 30, 2011 and 96% of the Company's oil and natural gas sales for the three and nine months ended September 30, 2010.

In Argentina, the Company has three significant customers, Refineria del Norte S.A (“Refiner”), Shell C.A.P.S.A. (“Shell”) and YPF S.A. (“YPF”). Sales to Refiner, Shell and YPF each accounted for 3% of the Company’s oil and natural gas sales for the three month period ended September 30, 2011 and 3%, 3% and 2% of the Company’s oil and natural gas sales for the nine months ended September 30, 2011. Sales to Refiner accounted for 4% of the Company’s oil and natural gas sales in each of the three and nine months ended September 30, 2010.

5. Property, Plant and Equipment

	As at September 30, 2011							As at December 31, 2010
(Thousands of U.S. Dollars)	Cost		Accumulated depletion, depreciation and accretion			Net book value		Cost		Accumulated depletion, depreciation and accretion			Net book value
Oil and gas properties
Proved	$	1,071,713	$	(492,501	)	$	579,212	$	777,262	$	(334,858	)	$	442,404
Unproved		430,870		-			430,870		278,753		-			278,753
		1,502,583		(492,501	)		1,010,082		1,056,015		(334,858	)		721,157
Furniture and fixtures and leasehold improvements		6,537		(4,051	)		2,486		5,233		(2,831	)		2,402
Computer equipment		7,389		(3,070	)		4,319		5,521		(2,358	)		3,163
Automobiles		1,081		(561	)		520		779		(477	)		302
Total Property, Plant and Equipment	$	1,517,590	$	(500,183	)	$	1,017,407	$	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 was $40.1 million and was recorded as a Corporate capital expenditure in 2011 and 2010. 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.

Depletion, depreciation, accretion and impairment ("DD&A") for the nine months ended September 30, 2011 includes an impairment loss of $40.8 million in Gran Tierra’s Peru cost center. This impairment loss relates to drilling and seismic costs from dry wells for two blocks, one of which was relinquished.

For the nine months ended September 30, 2010, a $3.7 million impairment loss was included in the Gran Tierra’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.

Table Of Contents

The amounts capitalized in each of the Company's cost centers during the nine months ended September 30, 2011 and the year ended December 31, 2010 were as follows:

	Nine Months Ended September 30, 2011

(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock based compensation	$	4,786	$	1,609	$	464	$	1,066	$	7,925
Capitalized stock based compensation	$	304	$	189	$	-	$	133	$	626

	Year ended December 31, 2010
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock based compensation	$	4,127	$	1,171	$	-	$	-	$	5,298
Capitalized stock based compensation	$	308	$	150	$	-	$	-	$	458

The unproved oil and natural gas properties at September 30, 2011 consist of exploration lands held in Colombia, Argentina, Peru, and Brazil, including additions related to Petrolifera’s assets. As at September 30, 2011, the Company had $301.6 million (December 31, 2010 - $228.8 million) of unproved assets in Colombia, $59.5 million (December 31, 2010 - $9.4 million) of unproved assets in Argentina, $28.0 million (December 31, 2010 - $28.2 million) of unproved assets in Peru, and $41.8 million (December 31, 2010 - $12.4 million) of unproved assets in Brazil for a total of $430.9 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 unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed. This assessment will include an impairment review.

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 September 30, 2011, outstanding share capital consists of 261,053,809 common voting shares of the Company, 8,763,980 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.

Warrants

At September 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. The 4,125,036 Replacement Warrants, issued upon the acquisition of Petrolifera (Note 3), to purchase 4,125,036 common shares for CDN$9.67, expired unexercised on August 28, 2011.

For the nine months ended September 30, 2011, 735,817 common shares were issued upon the exercise of 1,471,634 warrants (nine months ended September 30, 2010, 10,438,473 common shares were issued upon the exercise of 13, 731,008 warrants). Included in warrants exercised in the nine months ended September 30, 2010 were 7,145,938 warrants to purchase 7,145,938 common shares for $14.4 million, assumed on the acquisition of Solana in November 2008.

Stock Options

As at September 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.

Table Of Contents

The Company grants options to purchase common shares to certain directors, officers, employees and consultants. Each option permits the holder to purchase one common share at the stated exercise price. The options vest over three years and have a term of ten years, or three months after the grantee’s end of service to the Company, whichever occurs first. At the time of grant, the exercise price equals the market price. For the nine months ended September 30, 2011, 695,881 common shares were issued upon the exercise of 695,881 stock options (nine months ended September 30, 2010 – 2,324,256). The following options were outstanding as of September 30, 2011:

	Number of			Weighted Average
	Outstanding			Exercise Price
	Options			$/Option
Balance, December 31, 2010		10,943,058			3.49
Granted in 2011		3,920,996			8.17
Exercised in 2011		(695,881	)		(2.93	)
Forfeited in 2011		(387,501	)		(6.46	)
Balance, September 30, 2011		13,780,672			4.76

The weighted average grant date fair value for options granted in the nine months ended September 30, 2011 was $4.96 (nine months ended September 30, 2010 - $3.33). The intrinsic value of options exercised for the nine months ended September 30, 2011 was $3.5 million (nine months ended September 30, 2010 - $9.5 million).

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

	Number of		Weighted Average		Weighted
	Outstanding		Exercise Price		Average
Range of Exercise Prices ($/option)	Options		$/Option		Expiry Years
0.50 to 2.00		1,369,171		1.14		4.9
2.01 to 3.50		5,047,752		2.46		7.0
3.51 to 5.50		466,666		4.43		8.0
5.51 to 7.00		3,161,087		5.93		8.6
7.01 to 8.40		3,735,996		8.23		9.4
Total		13,780,672		4.76		7.8

The aggregate intrinsic value of options outstanding at September 30, 2011 is $16.9 million (December 31, 2010 - $49.9 million) based on the Company’s closing stock price of $4.77 (December 31, 2010 - $8.05) at that date. At September 30, 2011, there was $14.6 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 September 30, 2011, 6,089,622 (December 31, 2010 – 5,426,367) options were exercisable.

For the nine months ended September 30, 2011, the stock-based compensation expense was $10.0 million (nine months ended September 30, 2010 - $5.7 million) of which $8.5 million (nine months ended September 30, 2010 - $4.6 million) was recorded in G&A expenses, $0.9 million was recorded in operating expenses (nine months ended September 30, 2010 – $0.8 million) and $0.6 million of stock-based compensation was capitalized as part of exploration and development costs (nine months ended September 30, 2010 – $0.3 million).

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Dividend yield (per share)	$nil			$nil			$nil			$nil

Volatility		76	%		85	%		81	%		90	%
Risk-free interest rate		0.6	%		0.3	%		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	%

Table Of Contents

Weighted average shares outstanding

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
Weighted average number of common and exchangeable shares outstanding		277,608,572			254,951,642		272,006,775			252,487,462
Shares issuable pursuant to warrants		2,597,140			-		2,743,224			3,877,754
Shares issuable pursuant to stock options		4,350,662			-		5,504,270			3,929,287
Shares to be purchased from proceeds of stock options		(530,138	)		-		(768,374	)		-
Weighted average number of diluted common and exchangeable shares outstanding		284,026,236			254,951,642		279,485,895			260,294,503

Net Income per share

For the three months ended September 30, 2011, 4,040,996 options to purchase common shares (for the nine months ended September 30, 2011, 3,665,996 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 September 30, 2010, options to purchase 11,442,689 common shares and 9,147, 972 warrants to purchase 4,573,986 common shares were excluded from the diluted income per share calculation as the instruments were anti-dilutive. For the nine months ended September 30, 2010, options to purchase 3,435,000 common shares were excluded from the diluted income per share calculation as the instruments were anti-dilutive.

7. Asset Retirement Obligations

As at September 30, 2011, the Company’s asset retirement obligations were comprised of Colombian obligations in the amount of $4.9 million (December 31, 2010 - $3.7 million), Argentine obligations in the amount of $5.8 million (December 31, 2010 - $1.1 million) and Brazilian obligations in the amount of $0.4 million (December 31, 2010 - $nil). As at September 30, 2011, the undiscounted asset retirement obligations were $27.2 million (December 31, 2010 - $8.7 million). Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and gas properties were as follows:

	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2011			December 31, 2010
Balance, beginning of year	$	4,807		$	4,708
Settlements		(309	)		(286	)
Disposal		-			(720	)
Liability incurred		1,256			719
Liability assumed in a business combination (Note 3)		4,901			-
Foreign exchange		(1	)		58
Accretion		490			328
Balance, end of period	$	11,144		$	4,807

Asset retirement obligations - current	$	357		$	338
Asset retirement obligations - long term		10,787			4,469
Balance, end of period	$	11,144		$	4,807

Table Of Contents

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:

	Nine Months Ended September 30,
(Thousands of U.S. Dollars)		2011			2010
Income before income taxes		$	179,028		$	53,983
			35	%		35	%
Income tax expense expected			62,660			18,894
Other permanent differences			(2,507	)		4,721
Foreign currency translation adjustments			(1,100	)		12,060
Impact of foreign taxes			(4,704	)		(108	)
Enhanced tax depreciation incentive			-			(6,842	)
Stock-based compensation			2,987			1,519
Increase in valuation allowance			33,404			4,536
Branch and other foreign income pick-up in the United States and Canada			(4,627	)		(4,851	)
Non-deductible third party royalty in Colombia			6,145			-
Non-taxable gain on acquisition			(7,595	)		-
Total income tax expense		$	84,663		$	29,929

Current income tax			99,390			57,955
Deferred tax recovery			(14,727	)		(28,026	)
Total income tax expense		$	84,663		$	29,929

	As at
(Thousands of U.S. Dollars)		September 30, 2011			December 31, 2010
Deferred Tax Assets
Tax benefit of loss carryforwards		$	61,518		$	27,527
Tax basis in excess of book basis			29,988			7,975
Foreign tax credits and other accruals			16,789			16,895
Capital losses			2,444			1,413
Deferred tax assets before valuation allowance			110,739			53,810
Valuation allowance			(95,135	)		(48,958	)
		$	15,604		$	4,852

Deferred tax assets - current		$	2,504		$	4,852
Deferred tax assets - long term			13,100			-
			15,604			4,852

Deferred Tax Liabilities
Long-term - book value in excess of tax basis			(211,245	)		(204,570	)

Net Deferred Tax Liabilities		$	(195,641	)	$	(199,718	)

Table Of Contents

Equity tax for the nine months ended September 30, 2011 of $8.3 million represents a Colombian tax of 6% 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. The remainder of the equity tax liability at September 30, 2011 relates to an equity tax liability assumed upon the acquisition of Petrolifera.

As at September 30, 2011, the total amount of Gran Tierra’s unrecognized tax benefits was approximately $20.7 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 September 30, 2011, the amount of interest and penalties on unrecognized tax benefits included in current income tax liabilities in the condensed consolidated balance sheet was approximately $0.8 million. The Company had no interest or penalties included in the consolidated statement of operations for the three and nine months ended September 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		16,758
Unrecognized tax benefit at September 30, 2011	$	20,676

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.

As at September 30, 2011, the Company has deferred tax assets relating to net operating loss carryforwards of $61.5 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 tax assets relating to losses, $51.5 million (December 31, 2010 - $20.5 million) are generated by the foreign subsidiaries of the Company. Of the total tax assets relating to losses, $0.1 million will expire in 2011 (December 31, 2010 - $nil), $1.2 million (December 31, 2010 - $nil) will begin to expire in 2012 and $62.7 million (December 31, 2010 - $28.9 million) will begin to expire thereafter.

9 . 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, $16,000 for vehicle and equipment leases and $6,400 for certain employee accommodation leases in Canada, Colombia, Argentina, Peru, and Brazil.

Table Of Contents

Future lease payments at September 30, 2011, including the aforementioned operating leases, are as follows:

	As at September 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	$	9,436	$	5,612	$	3,239	$	585	$	-
Software and telecommunication		2,017		1,221		754		42		-
Drilling, completion, facility construction and oil transportation services		112,546		80,766		30,153		1,627		-
Consulting		518		518		-		-		-
Total	$	124,517	$	88,117	$	34,146	$	2,254	$	-

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.

Legal 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 Bogota. At this time no amount has been accrued in the financial statements as the Company does not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $5.4 million.

Gran Tierra 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 September 30, 2011 is $8.2 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 probable and 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.

Table Of Contents

10. Financial Instruments, Fair Value Measurements and Credit Risk

The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities. 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 September 30, 2011, the fair values of financial instruments approximate their carrying amounts due to the short term maturity of these instruments.

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 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. The Company does not have any assets or liabilities whose fair value is measured using the Level 1 or 2 methods.

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.

The Company’s revenues are derived from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. For the nine months ended September 30, 2011, the Company had one significant customer for its Colombian crude oil, Ecopetrol, and in Argentina the Company had three significant customers, Refiner, Shell and YPF.

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 $98,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

11. Bank Debt and Credit Facilities

Effective July 30, 2010, a subsidiary of 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 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 G&A expense. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. As at September 30, 2011, the Company had not drawn down any amounts under this facility.

As part of the acquisition of Petrolifera , Gran Tierra assumed a reserve-backed credit facility with an outstanding balance as at the Acquisition Date of $31.3 million. The Company repaid this credit facility on August 5, 2011. The credit facility bore interest at LIBOR plus 8.25% and was partially secured by the pledge of the shares of Petrolifera’s subsidiaries.

Interest Expense

Interest expense on the reserve-backed credit facility for the 140 day period from the Acquisition Date to August 5, 2011, the date the facility was repaid, was $1.6 million. This amount is recorded in the Condensed Consolidated Statements of Operations and Retained Earnings as part of G&A expense.

Restricted cash

Restricted cash comprises cash resources pledged to secure letters of credit. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts. Restricted cash is classified between current and long term assets based on the expiration dates of the deposits underlying the letters of credit.

12. Related Party Transaction

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 $4,300 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.

Table Of Contents

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 nine months ended September 30, 2011, $2.3 million was capitalized and at September 30, 2011, $0.1 million was included in accounts payable related to this contract, the terms of which are consistent with market conditions.

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 ran from February 1, 2009 to August 31, 2011 and the sublease payment was $8,551 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.

Table Of Contents

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.

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

On June 15, 2011, we completed the acquisition of a 70% participating interest in four blocks in Brazil. The agreement had an effective date of September 1, 2010. Purchase consideration totalled $40.1 million. With the exception of one block which has a producing well, the remaining blocks are unproved properties.

Highlights

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			% Change		2011		2010		% Change

Production - Barrels of Oil Equivalent ("boe") per Day (1)		18,369		13,536			36		17,033		13,949		22

Prices Realized - per boe	$	89.25	$	67.54			32	$	93.50	$	68.48		37

Revenue and Other Income ($000s)	$	151,033	$	84,569			79	$	435,672	$	261,793		66

Net Income (Loss) ($000s)	$	49,085	$	(3,277	)		-	$	94,365	$	24,054		292

Net Income Per Share - Basic	$	0.18	$	(0.01	)		-	$	0.35	$	0.10		250

Net Income Per Share - Diluted	$	0.17	$	(0.01	)		-	$	0.34	$	0.09		278

Funds Flow From Operations ($000s) (2)	$	72,817	$	37,185			96	$	227,949	$	135,519		68

Capital Expenditures ($000s)	$	58,564	$	47,686			23	$	229,155	$	102,046		125

Table Of Contents

	As at

	September 30, 2011		December 31, 2010		% Change


Cash & Cash Equivalents ($000s)	$	226,370	$	355,428		(36	)

Working Capital (including cash & cash equivalents) ($000s)	$	230,508	$	265,835		(13	)

Property, Plant & Equipment ($000s)	$	1,017,407	$	727,024		40

(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 generally accepted accounting principles ("GAAP"). Management uses this financial measure to analyze operating performance and the income (loss) generated by our 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 our 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. Our 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:

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

Net income (loss)	$	49,085		$	(3,277	)	$	94,365		$	24,054
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A		49,852			35,254			160,174			107,238
Deferred taxes		(10,082	)		(9,995	)		(15,488	)		(28,026	)
Stock-based compensation		3,438			2,064			9,383			5,424
Unrealized gain on financial instruments		-			-			(1,354	)		(44	)
Unrealized foreign exchange (gain) loss		(15,966	)		13,139			136			27,136
Settlement of asset retirement obligations		-			-			(309	)		(263	)
Equity taxes		(3,510	)		-			2,741			-
Gain on acquisition		-			-			(21,699	)		-
Funds flows from operations	$	72,817		$	37,185		$	227,949		$	135,519

Table Of Contents

Operational Highlights and Developments

In the third quarter of 2011, oil and gas production (net after royalty and inventory adjustments) increased by 36% to 18,369 barrels of oil equivalent per day (“boepd”) net after royalty (“NAR”) compared with the third quarter of 2010. The production increase was mainly due to a full quarter of production of 2,559 boepd from Petrolifera’s properties, improved production from the Costayaco field and the absence of any pipeline or other operational disruptions. For the nine months ended September 30, 2011, oil and gas production increased by 22% to 17,033 boepd compared with the same nine month period of 2010. Production from Petrolifera’s properties was 1,688 boepd during this period.

Average prices realized per boe in the third quarter of 2011, increased by 32% to $89.25 compared with the third quarter of 2010. For the nine months ended September 30, 2011, the average price realized per boe increased by 37% to $93.50 from the comparable nine month period in 2010.

Successful Melero-1 exploration well on the Garibay Block in the Llanos basin, Colombia tested 922 gross barrels of oil per day.

Three exploration wells drilled in the Rinconada Norte Block of the Neuquen Basin, Argentina made new discoveries of oil, one of which tested 1,023 boe gross per day. A wholly-owned subsidiary of America Petrogas Inc. is the operator of the Rinconada Norte Block with a 65% working interest upon completing certain work program obligations, while we hold a 35% working interest.

We announced two farm-in agreements with Statoil do Brasil Ltda. ("Statoil") in a joint venture with PetróleoBrasileiro S.A. ("Petrobras"), in Brazil ’ s deepwater offshore Camamu-Almada Basin, subject to obtaining regulatory approval from Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP").

Subsequent to end of the third quarter 2011, we announced an acreage swap in Colombia with a wholly-owned subsidiary of Compania Espanola de Petroleos, S.A. (“CEPSA”), resulting in additional exploration opportunities in the foothills of the Llanos Basin subject to obtaining regulatory approval from Colombia’s Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”).

Financial Highlights

Increased production levels and improved crude oil prices contributed to a 79% increase in revenue and other income to $151.0 million for the third quarter of 2011 compared with the third quarter of 2010. The same contributing factors increased revenue and other income by 66% to $435.7 million for the nine months ended September 30, 2011.

Increased oil and natural gas sales and a foreign exchange gain, partially offset by increased DD&A, operating and general and adminstrative ("G&A") expenses, resulted in net income of $49.1 million, or $0.18 per share basic and $0.17 per share diluted, for the third quarter of 2011. This compares with a loss of $3.3 million, or $0.01 per basic and diluted share, in the third quarter of 2010. Net income increased by 292% to $94.4 million, or $0.35 per basic share and $0.34 per diluted share, for the nine months ended September 30, 2011 compared with $24.1 million, or $0.10 per basic share and $0.09 per diluted share, in the comparable nine month period in 2010. The improvement in net income for the nine months ended September 30, 2011 is a result of increased oil and natural gas sales, a gain on the Petrolifera acquisition and a reduced foreign exchange loss, partially offset by an impairment loss recorded in the Peru cost center, a Colombian equity tax and increased DD&A, operating and G&A expenses.

Table Of Contents

Increased production levels and improved crude oil prices, partially offset by increased operating and G&A expenses, contributed to increased funds flow from operations for both comparative periods.

Cash and cash equivalents of $226.4 million at September 30, 2011 decreased from $355.4 million at December 31, 2010 primarily as a result of $248.8 million of capital expenditures and an increase in non-cash working capital of $87.4 million, partially offset by funds flow from operations of $227.9 million, during the nine months ended September 30, 2011.

Working capital (including cash and cash equivalents) was $230.5 million at September 30, 2011, which is a $35.3 million decrease from December 31, 2010, due mainly to lower cash and cash equivalents, partially offset by a $100.5 million increase in accounts receivable due to the timing of payments from Ecopetrol.

Property, plant and equipment as at September 30, 2011 was $1.0 billion, an increase of $290.4 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 expense.

Business combination

On March 18, 2011 (the "Acquisition Date"), we completed the acquisition of all the issued and outstanding common shares and warrants of Petrolifera pursuant to the terms and conditions of an 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 was accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed were recorded at their fair values as at the Acquisition Date and the results of Petrolifera were 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.

Table Of Contents

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, we 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, we 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.

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 from the Acquisition Date to September 30, 2011 amounted to 1,688 boepd (2,559 boepd for the third quarter of 2011) with oil and natural gas sales of $22.3 million (third quarter 2011 - $11.4 million). For the period post acquisition, Petrolifera recorded a loss after tax of $2.8 million.

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 we are 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.

Table Of Contents

REVIEW OF CONSOLIDATED RESULTS

	Three Months Ended September 30,									Nine Months Ended September 30,
Consolidated Results of Operations	2011			2010			% Change			2011			2010			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	150,824		$	84,110			79		$	434,784		$	260,759			67
Interest		209			459			(54	)		888			1,034			(14	)
		151,033			84,569			79			435,672			261,793			66

Operating expenses		21,727			19,401			12			61,283			39,028			57
DD&A expense		49,852			35,254			41			160,174			107,238			49
G&A expenses		16,316			10,977			49			46,364			27,848			66
Equity tax		-			-			-			8,271			-			-
Financial instruments gain		-			-			-			(1,522	)		(44	)		-
Gain on acquisition		-			-			-			(21,699	)		-			-
Foreign exchange (gain) loss		(15,921	)		16,320			(198	)		3,773			33,740			(89	)
		71,974			81,952			(12	)		256,644			207,810			23

Income before income taxes		79,059			2,617			-			179,028			53,983			232
Income tax expense		(29,974	)		(5,894	)		409			(84,663	)		(29,929	)		183
Net income (loss)	$	49,085		$	(3,277	)		-		$	94,365		$	24,054			292

Production, Net of Royalties

Oil and NGL's ("bbl") (1)		1,604,242			1,229,768			30			4,492,430			3,775,704			19
Natural gas ("mcf") (1)		514,086			93,384			451			945,240			193,452			389
Total production ("boe") (1) (2)		1,689,923			1,245,332			36			4,649,970			3,807,946			22

Average Prices

Oil and NGL's ("per bbl")	$	92.76		$	68.12			36		$	96.02		$	68.87			39
Natural gas ("per mcf")	$	3.92		$	3.64			8		$	3.64		$	3.85			(5	)

Consolidated Results of Operations ("per boe")

Oil and natural gas sales	$	89.25		$	67.54			32		$	93.50		$	68.48			37
Interest		0.12			0.37			(68	)		0.19			0.27			(30	)
		89.37			67.91			32			93.69			68.75			36

Operating expenses		12.86			15.58			(17	)		13.18			10.25			29
DD&A expense		29.50			28.31			4			34.45			28.16			22
G&A expenses		9.65			8.81			10			9.97			7.31			36
Equity tax		-			-			-			1.78			-			-
Foreign exchange (gain) loss		(9.42	)		13.10			(172	)		0.81			8.86			91
Gain on acquisition		-			-			-			(4.67	)		-			-
Financial instruments gain		-			-			-			(0.33	)		(0.01	)		-
		42.59			65.80			(35	)		55.19			54.57			1

Income before income taxes		46.78			2.12			-			38.50			14.18			172
Income tax expense		(17.74	)		(4.73	)		275			(18.21	)		(7.86	)		132
Net income (loss)	$	29.04		$	(2.62	)		-		$	20.29		$	6.32			221

Table Of Contents

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

(2)	Natural gas liquids (“NGL”) volumes are converted to a boe equivalent 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 are Colombia, Argentina and Peru. Brazil is not a reportable segment because the level of activity in Brazil is not significant at this time. For the three and nine months ended September 30, 2011, Colombia generated 88% and 92%, respectively, of our revenue and other income compared with 96% of revenue and other income for the three and nine months ended September 30, 2010. The decline in percentage contribution from the Colombian segment is a result of the inclusion of Petrolifera’s oil and natural gas sales for the period beginning March 18, 2011. Petrolifera’s oil and natural gas sales primarily relate to the Argentina reportable segment.

Net income was $49.1 million, or $0.18 per share basic and $0.17 per share diluted, in the third quarter of 2011 compared with a net loss of $3.3 million, or $0.01 per share basic and diluted, for the third quarter of 2010. Increased oil and natural gas sales due to increased production and higher realized crude oil prices and a foreign exchange gain were partially offset by increased operating, DD&A and G&A expenses.

For the nine months ended September 30, 2011, net income increased to $94.4 million, a 292% improvement from the comparable nine month period in 2010. On a per share basis, net income improved to $0.35 per share basic and $0.34 per share diluted from $0.10 basic and $0.09 diluted per share in the comparable period of 2010. Increased oil and natural gas sales due to increased production and higher crude oil prices, a $21.7 million gain recorded on the Petrolifera acquisition and lower foreign exchange losses were partially offset by a $40.8 million impairment loss recorded in the Peru cost center, a Colombian equity tax of $8.3 million and increased operating, DD&A and G&A expenses.

Crude oil and NGL production , net after royalties, for the third quarter of 2011 increased to 1,604,242 barrels, a 30% improvement from the third quarter of 2010. The increase was due to production from Petrolifera (160,177 barrels), improved production levels from the Costayaco field and the absence of pipeline interruptions. For the nine months ended September 30, 2011, production of crude oil increased by 19% to 4,492,430 barrels. Petrolifera’s crude oil and NGL production for the period since the Acquisition Date was 332,897 barrels. Production during the first quarter of 2011 was adversely affected by a 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. During the nine months ended September 30, 2010, sections of the Trans Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 22 days.

Average realized crude oil prices for the third quarter of 2011 increased by 36% to $92.76 per barrel from $68.12 per barrel in the third quarter of 2010 and by 39% to $96.02 per barrel for the nine months ended September 30, 2011 from $68.87 for the comparable nine month period in 2010 reflecting higher West Texas Intermediate (“WTI”) oil prices and the premium to WTI received in Colombia during the nine months ended September 30, 2011. Average WTI for the three and nine months ended September 30, 2011 was $89.70 and $95.40, respectively.

Increased production and higher crude oil prices resulted in a 79% increase in revenue and other income to $151.0 million for the third quarter of 2011 and a 66% increase to $435.7 million for the nine months ended September 30, 2011, compared with comparative 2010 periods.

Operating expenses for the third quarter of 2011 amounted to $21.7 million, or $12.86 per boe, compared with $19.4 million or $15.58 per boe, in the third quarter of 2010. The third quarter increase in operating expenses was mainly due to an increase of $5.7 million in operating costs in Argentina ($5.5 million related to properties acquired from Petrolifera), partially offset by a decrease of $3.9 million in operating costs in Colombia due to lower transportation costs as a result of the absence of pipeline disruptions and lower workover costs. The third quarter reduction in operating costs on a per boe basis was a result of increases in production more than offsetting increased operating costs.

Operating expenses for the nine months ended September 30, 2011, increased to $61.3 million or $13.18 per boe, from $39.0 million or $10.25 per boe, in the comparable nine month period of 2010. The increase in operating expenses for the nine months ended September 30, 2011, was mainly due to an increase of $12.5 million in operating costs in Argentina ($10.6 million related to properties acquired from Petrolifera) and an increase of $9.1 million in Colombia as a result of expanded operations.

DD&A expense for the third quarter of 2011 increased to $49.9 million compared with $35.3 million in the third quarter of 2010. The increase was attributable to increased production levels as the depletion rate of $29.50 per boe remained comparable to the third quarter of 2010. DD&A expense for the third quarter of 2011 included $5.9 million related to properties acquired from Petrolifera and a $7.4 million impairment loss related to the Peru cost center. Increased costs in the depletable pools were more than offset by increased reserves.

Table Of Contents

For the nine months ended September 30, 2011, DD&A expense increased to $160.2 million from $107.2 million in the comparable nine month period in 2010 due to increased production and a $40.8 million impairment loss recorded in our Peru cost center. This resulted in an increase in DD&A expense to $34.45 per boe in the nine month period compared with $28.16 per boe recorded in the comparable nine month period in 2010. DD&A expense on the Petrolifera properties for the nine months ended September 30, 2011 was $10.7 million. For the nine months ended September 30, 2010, a $3.7 million ceiling test impairment loss was included in our Argentina cost center.

G&A expenses of $16.3 million and $46.4 million for the three and nine months ended September 30, 2011, respectively, were higher than comparable periods in 2010 due to increased employee related costs reflecting the expanded operations in all business segments and $1.2 million of expenses associated with the acquisition of Petrolifera. G&A expenses for Petrolifera’s operations were $2.6 million and $5.6 million for the three and nine months ending September 30, 2011 (including interest on bank debt of $0.8 million and $1.6 million respectively). G&A expenses per boe increased 10% to $9.65 per boe for the current quarter, compared with $8.81 per boe for the third quarter of 2010, and increased by 36% to $9.97 per boe for the nine months ended September 30, 2011 compared with $7.31 for the comparable nine month period in 2010 due to the same factors.

Equity tax represents a Colombian tax of 6% on the balance sheet equity of our Colombian segment at January 1, 2011.

The gain on acquisition recognised in the nine months ended September 30, 2011 relates to the acquisition of Petrolifera. This gain reflects the impact on Petrolifera’s pre-acquisition market value of its lack of liquidity and capital resources required to maintain production and reserves and further develop and explore its inventory of prospects.

The foreign exchange gain in the three months ended September 30, 2011 was due to the strengthening of the U.S. dollar in relation to the Colombian Peso and included the translation of deferred tax liabilities denominated in Colombian pesos.

Income tax expense for the third quarter of 2011 amounted to $30.0 million compared with $5.9 million in the third quarter of 2010. For the nine months ended September 30, 2011, income tax expense amounted to $84.7 million compared with $29.9 million in the comparable nine month period in 2010. In 2011, higher income before income taxes resulted in increased income taxes. For the nine months ended September 30, 2011, the effective income tax rate was 47% compared with 55% in the comparable nine month period in 2010 due to an increase in foreign currency translation adjustments and the inclusion of the non-taxable gain on acquisition, partially offset by an increase in the valuation allowance on losses incurred mainly in Peru. The variance in the effective tax rates compared with the 35% U.S. statutory rate is attributable to the same factors and other permanent differences.

2011 Work Program and Capital Expenditure Program

Our capital expenditures during the third quarter of 2011 were $58.6 million increasing the year to date capital expenditures to $229.2 million. These expenditures represent a significant increase from the comparative periods in 2010 of $47.7 million and $102.0 million, respectively.

Our 2011 capital program outlook for 2011 of $379 million includes $233 million for Colombia, $61 million for Brazil, $42 million for Argentina, and $43 million for Peru. Of this, $254 million is for drilling and acquisitions, $56 million is for facilities and pipelines and $69 million is for geological and geophysical (“G&G”) expenditures. Of the $254 million allocated to drilling and acquisitions, approximately $113 million is for exploration, $48 million is for acquisitions and the balance is for delineation and development drilling. Acquisition expenditures include $28 million for the June 2011 acquisition of a 70% participating interest in four blocks in the onshore Recôncavo Basin of Brazil and $20 million for the recently announced acquisition of an interest in the Llanos 22 block in Colombia. We expect that our committed and discretionary 2011 capital program can be funded from cash flow from operations and cash on hand.

Our 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.

Table Of Contents

REVIEW OF OPERATIONS IN COLOMBIA

	Three Months Ended September 30,								Nine Months Ended September 30,
Segmented Results of Operations – Colombia	2011			2010		% Change			2011		2010		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	133,475		$	80,731		65		$	399,252	$	250,767		59
Interest		130			301		(57	)		375		520		(28	)
		133,605			81,032		65			399,627		251,287		59

Operating expenses		13,222			17,090		(23	)		41,565		32,480		28
DD&A expense		34,916			33,916		3			104,560		99,243		5
G&A expenses		6,426			4,391		46			15,166		11,190		36
Equity tax		-			-		-			8,271		-		-
Foreign exchange (gain) loss		(17,462	)		17,330		(201	)		1,947		34,220		(94	)
		37,102			72,727		(49	)		171,509		177,133		(3	)

Segment income before income taxes	$	96,503		$	8,305		-		$	228,118	$	74,154		208

Production, Net of Royalties

Oil and NGL's ("bbl") (1)		1,355,661			1,162,961		17			3,939,486		3,567,377		10
Natural gas ("mcf") (1)		70,884			93,384		(24	)		186,456		193,452		(4	)
Total production ("boe") (1) (2)		1,367,475			1,178,525		16			3,970,562		3,599,619		10

Average Prices

Oil and NGL's ("per bbl")	$	98.07		$	69.22		42		$	101.09	$	70.08		44
Natural gas ("per mcf")	$	7.37		$	3.66		101		$	5.37	$	3.88		38

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	97.61		$	68.50		42		$	100.55	$	69.66		44
Interest		0.10			0.26		(62	)		0.09		0.14		(36	)
		97.71			68.76		42			100.64		69.80		44

Operating expenses		9.67			14.50		(33	)		10.47		9.02		16
DD&A expense		25.53			28.78		(11	)		26.33		27.57		(4	)
G&A expenses		4.70			3.73		26			3.82		3.11		23
Equity tax		-			-		-			2.08		-		-
Foreign exchange (gain) loss		(12.77	)		14.70		(187	)		0.49		9.51		(95	)
		27.13			61.71		(56	)		43.20		49.21		(12	)

Segment income before income taxes	$	70.58		$	7.05		901		$	57.45	$	20.59		179

Table Of Contents

(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 nine months ended September 30, 2011, income before income taxes in Colombia amounted to $96.5 million and $228.1 million respectively, compared with $8.3 million and $74.2 million in the comparative periods in 2010. The increases are mainly the result of increased oil sales due to increased production and higher prices and a foreign exchange gain, partially offset by increases in operating, DD&A and G&A expenses and Colombian equity tax.

For the third quarter of 2011, production of crude oil and NGLs , net after royalties, increased by 17% to 1,355,661 barrels compared with 1,162,961 barrels for the third quarter of 2010. The increase is primarily due to improved production levels from the Costayaco field and the absence of any pipeline disruptions during the quarter. Production for the nine months ended September 30, 2011 amounted to 3,939,486 barrels compared with 3,567,377 barrels, an increase of 10%, from the comparable nine month period in 2010. Production during the first quarter of 2011 was adversely affected by a 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 third quarter of 2010, sections of the Trans-Andean Pipeline were damaged, which temporarily reduced our deliveries to Ecopetrol for 22 days.

As a result of achieving gross field production of five million barrels in the Costayaco field during the month of September 2009, we are now subject to an additional government royalty. 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 ANH 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 other income for the three and nine months ended September 30, 2011 increased by 65% to $133.6 million and by 59% to $399.6 million, respectively, from the comparable 2010 periods. Oil and natural gas sales were positively impacted by higher net realized crude oil prices in 2011 and increased production. The average net realized price for crude oil for the third quarter of 2011 was $98.07 per barrel, an increase of 42% from the third quarter of 2010. For the nine months ended September 30, 2011, the average realized price increased by 44% to $101.09 per barrel compared with the same period in 2010. We received a premium to WTI during the three and nine months ended September 30, 2011 related to Colombian Pacific Blend prices.

Operating expenses for the third quarter of 2011 decreased to 13.2 million, or $9.67 per boe, from $17.1 million, or $14.50 per boe, for the third quarter of 2010. The decrease per boe was primarily due to lower trucking costs resulting from the absence of pipeline disruptions and significantly lower workover costs which more than offset the impact of increased activity in 2011. For the nine months ended September 30, 2011, operating expenses amounted to $41.6 million, or $10.47 per boe, compared with $32.5 million, or $9.02 per boe, for the comparable nine month period in 2010. Operating expenses per boe were higher in 2011 year to date due to increased long-term testing and trucking costs and an increase in the number of wells.

For the third quarter of 2011, DD&A expense increased to $34.9 million from $33.9 million in the third quarter of 2010. The increase was attributable to higher production levels offset by a reduction in the depletion rate to $25.53 per boe compared with $28.78 per boe in the third quarter of 2010. The reduced depletion rate was due to increased reserves in the Colombian cost center. DD&A expense for the nine months ended September 30, 2011 amounted to $104.6 million, or $26.33 per boe, essentially unchanged from the comparable nine month period in 2010. The impact of a 10% increase in production was offset by higher crude oil proved reserves. Also, increased levels of costs in our depletable pools were offset by higher reserves.

G&A expensse increased to $6.4 million ($4.70 per boe) for the third quarter of 2011 from $4.4 million ($3.73 per boe) incurred in the third quarter of 2010. The increase was mainly due to increased salaries and stock based compensation resulting from an increased headcount and staff changes and consulting fees related to an expansion in development and operating activities. For the nine months ended September 30, 2011, G&A expenses increased to $15.2 million ($3.82 per boe) from $11.2 million ($3.11 per boe) incurred for the comparable nine month period of 2010, for the same reasons.

Equity tax of $8.3 million for the nine months ended September 30, 2011 represents a Colombian tax of 6% on the balance sheet equity of the Colombian segment 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.

Table Of Contents

The results for the third quarter of 2011 include a foreign exchange gain of $17.5 million, of which $15.3 million is an unrealized non cash foreign exchange gain on the translation of Colombian peso denominated deferred taxes to the U.S. dollar functional currency. Under U.S. 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 $98,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar. For the third quarter of 2010, the foreign exchange loss was $17.3 million, of which $13.1 million was unrealized. For the nine months ended September 30, 2011 the foreign exchange loss of $1.9 million (2010: $34.2 million) included an unrealized loss of $0.6 million (2010: $27.0 million).

Capital Program - Colombia

Capital expenditures during the third quarter of 2011 in Colombia were $40.1 million bringing the total expenditures for the nine months ended September 30, 2011 to $136.6 million, an increase of 99 % from the comparable nine month period in 2010. The following table provides a breakdown of capital expenditures during 2011 and 2010:

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

Drilling and Completion	$	26.7		$	14.4		$	83.5	$	39.5
Facilities and Equipment		5.3			6.8			30.3		20.0
G&G		9.3			3.7			19.4		10.9
Other		(1.2	)		(2.8	)		3.4		(1.9	)
	$	40.1		$	22.1		$	136.6	$	68.5

The significant elements of our third quarter 2011 Capital Program in Colombia are summarized below:

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

The Moqueta-6ST1 delineation well was drilled and a testing program has been initiated to confirm the nature of the fluids and reservoir productivity of the sandstones, with results expected in approximately one month. Flowline construction was completed during July 2011 to transfer production from the Moqueta field to our Costayaco – 7 facilities. A parallel four inch gas line was completed that will be used to transport gas from Costayaco to Moqueta for anticipated gas injection for pressure support.

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

The Costayaco-14 development well was drilled as a water injector for pressure support in the Costayaco field.

Garibay Block, Llanos Basin (50% working interest and Non-Operated)

The Jilguero-2 appraisal well on the Garibay Block was spud on September 10, 2011. This well is located at the Jilguero oil discovery made by the joint venture between a subsidiary of Gran Tierra and a wholly-owned subsidiary of CEPSA. The Jilguero-2 well reached total measured depth during October 2011.

The Melero-1 exploration well spud on June 22, 2011, and reached total measured depth at 9,748 feet on July 16, 2011. Four drill stem tests were run and average gross production of 922 barrels of oil per day of 16.8 degrees API gravity was obtained. This well is currently suspended for long-term testing expected to begin in January 2012.

Table Of Contents

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

A 275 square kilometer 3D seismic program was acquired in the third quarter of 2011 and is being used to map the field and additional exploration prospects nearby. Approximately 222 square kilometers of data was acquired in the Sierra Nevada license and 53 square kilometers was in the Magdalena license.

Outlook – Colombia

The 2011 capital program in Colombia is $233 million with $150 million allocated to drilling and acquisitions, $48 million to facilities and pipelines and $35 million for G&G expenditures. Acquisition expenditures include $20 million for the recently announced acquisition of an interest in the Llanos 22 block in Colombia.

Our planned work program for the fourth quarter of 2011 includes includes the following:

Exploration Activities:

The Rumiyaco-1 oil exploration well in the Rumiyaco Block in the Putumayo Basin began drilling on October 9, 2011. The well is expected to reach total measured depth of approximately 10,700 feet in December 2011.

The Pacayaco-1 ST1 oil exploration well on the Chaza block of the Putumayo basin is expected to spud in December, 2011.

The Ramiriqui-1 oil exploration well in the Llanos-22 block operated by CEPSA (GTE 45% working interest) is currently drilling ahead and is expected to reach total depth in December 2011.

The Turpial-1 oil exploration well in the Turpial Block in the Middle Magdelena Basin has been deferred to 2012.

La Vega Este-1 oil exploration well in the Azar Block has been deferred to 2012.

Development and Delineation Activities:

The Brillante SE-2x well began drilling on October 20, 2011, with the intent to define adequate reserves to justify the construction of a gas pipeline and commit to long term gas sales contracts. The well is expected to reach total measured depth of approximately 6,000 feet in November 2011. A second delineation well may be drilled in late 2011 or early 2012.

Seismic

New 3D seismic acquisition is expected to start in the fourth quarter to assist in refining the mapping of the Moqueta field and planning further delineation and development drilling.

Table Of Contents

REVIEW OF OPERATIONS IN ARGENTINA

	Three Months Ended September 30,									Nine Months Ended September 30,
Segmented Results of Operations - Argentina	2011			2010			% Change			2011		2010		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	15,188		$	3,379			350		$	33,038	$	9,992		231
Interest		(22	)		-			-			6		19		(68	)
		15,166			3,379			349			33,044		10,011		230

Operating expenses		7,946			2,266			251			18,921		6,408		195
DD&A expense		6,508			1,208			439			13,161		7,699		71
G&A expenses		2,389			353			577			6,086		1,958		211
Foreign exchange (gain) loss		(54	)		(43	)		(26	)		28		104		(73	)
		16,789			3,784			344			38,196		16,169		136

Segment loss before income taxes	$	(1,623	)	$	(405	)	301		$	(5,152	)	$	(6,158	)	(16	)

Production, Net of Royalties

Oil and NGL's ("bbl") (1) (2)		227,157			66,807		240			527,507			208,327		153
Natural gas ("mcf") (2)		443,202			-		-			758,784			-		-
Total production ("boe") (2) (3)		301,024			66,807		351			653,971			208,327		214

Average Prices

Oil and NGL's ("per bbl")	$	60.29		$	50.58		19		$	58.00		$	47.96		21
Natural gas ("mcf") (1)	$	3.37		$	-		-		$	3.22		$	0.09		-

Segmented Results of Operations ("per boe")

Oil and natural gas sales	$	50.46		$	50.58		-		$	50.52		$	47.96		5
Interest		(0.07	)		-		-			0.01			0.09		(89	)
		50.39			50.58		-			50.53			48.05		5

Operating expenses		26.40			33.92		(22	)		28.93			30.76		(6	)
DD&A expense		21.62			18.08		20			20.12			36.96		(46	)
G&A expenses		7.94			5.28		50			9.31			9.40		(1	)
Foreign exchange loss (gain)		(0.18	)		(0.64	)	72			0.04			0.50		(92	)
		55.78			56.64		(2	)		58.40			77.61		(25	)

Segment loss before income taxes	$	(5.39	)	$	(6.06	)	(11	)	$	(7.87	)	$	(29.57	)	(73	)

(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 equivalent 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 and nine months ended September 30, 2011, loss before income taxes in Argentina amounted to $1.6 million and $5.2 million respectively, compared with $0.4 million and $6.2 million in the comparative periods in 2010. Increased o il and natural gas sales were more than offset by increased operating, DD&A and G&A expenses and an increase in the foreign exchange loss. Results of the Argentina segment were significantly affected by the inclusion of Petrolifera’s results since the Acquisition Date. The impact of Petrolifera on the financial and operational results of the Argentina segment is discussed below.

Crude oil and NGL production increased 240% to 227,157 barrels for the third quarter of 2011 compared with 66,807 barrels for the third quarter of 2010. For the nine months ended September 30, 2011, production increased by 153% to 527,507 barrels compared with 208,327 barrels in the comparable nine month period in 2010. The increase resulted from the inclusion of Petrolifera production of 160,177 barrels for the third quarter of 2011 and 332,879 barrels for the nine months ended September 30, 2011.

Natural gas sales relate solely to Petrolifera’s properties. Natural gas sales amounted to 443 million cubic feet in the third quarter of 2011 and 759 million cubic feet for the nine months ended September 30, 2011.

Table Of Contents

Overall, total production of oil and gas from the Argentina segment increased by 351% to 301,024 boe for the third quarter of 2011 and by 214% to 653,971 boe for the nine months ended September 30, 2011.

Due to the Argentinean regulatory regime, the average oil price we received for production from our blocks during the third quarter of 2011 was approximately $60.29 per barrel. Currently most oil and gas producers in Argentina are operating without sales contracts for periods longer than several months. We are continuing deliveries to refineries and are negotiating a price for those deliveries on a regular and short term basis.

Average regulated crude oil prices increased by 19% for the third quarter of 2011 compared with the third quarter of 2010. Increased prices together with higher production levels due to the inclusion of Petrolifera’s oil and gas production, resulted in revenue and other income increasing by 349 % to $15.2 million in the third quarter of 2011 compared with the third quarter of 2010. For the nine months ended September 30, 2011, a 21% increase in average crude oil prices together with increased crude oil production and the recording of natural gas sales from Petrolifera’s properties, resulted in an increase in revenue and other income of 230% to $33.0 million compared with the comparable nine month period in 2010.

Operating expenses for the third quarter of 2011, amounted to $7.9 million, or $26.40 per boe, compared with $2.3 million, or $33.92 per boe, incurred in the third quarter of 2010. The increase in operating expenses was due to the inclusion of Petrolifera’s operating expenses of $5.5 million in the third quarter of 2011. The reduction in operating expenses on a boe basis was due to lower per boe transportation costs on Petrolifera’s properties. Operating expenses for the nine months ended September 30, 2011 increased to $18.9 million compared with $6.4 million for the comparable nine month period in 2010. Petrolifera’s operating expenses in the period since the Acquisition Date were $10.6 million. On a per boe basis, operating expenses decreased to $28.93 per boe in the nine months ended September 30, 2011 from $30.76 per boe for the nine month period ended September 30, 2010. The decrease in operating expense per boe was due to the same factors as the third quarter.

DD&A expense for the third quarter of 2011 was $6.5 million compared with $1.2 million in the third quarter of 2010. The increase is primarily due to the inclusion of DD&A expense for Petrolifera ($4.5 million). On a boe basis DD&A expense increased to $21.62 from $18.08 due to an increase in the depletable base cost pools, partially offset by increased reserves.

For the nine months ended September 30, 2011, DD&A expense was $13.2 million compared with $7.7 million in the comparable nine months of 2010. DD&A expense for the nine month period in 2011 included $9.3 million from Petrolifera’s properties. In 2010, DD&A expense included a $3.7 million impairment loss. DD&A expense per boe for the nine months ended September 30, 2011 is $20.12, significantly lower than DD&A expense in the nine months ended September 30, 2010 of $36.96 due to the inclusion of an impairment loss of $17.76 per boe in 2010.

G&A expenses for the three and nine months ended September 30, 2011 increased from the comparable periods in 2010 due to the inclusion of Petrolifera’s G&A for the period after acquisition ($1.2 million for the three months ended September 30, 2011 and $2.7 million for the period since acquisition, including interest expense on bank debt of $0.8 million for the three month period ended September 30, 2011 and $1.6 million for the period since acquisition) and increased headcount as a result of expanded operations.

Capital Program - Argentina

Capital expenditures in Argentina amounted to $7.1 million during the third quarter of 2011 bringing the total expenditures for the nine months ended September 30, 2011 to $25.9 million. Capital expenditures in the nine months ended September 30, 2011 included drilling expenditures of $22.9 million, facilities expenses of $3.4 million, G&G expenses of $2.1 million and other expenditures of $2.0 million. These expenditures were partially offset by proceeds of $3.3 million from the farm out of a property and $1.2 million from the sale of a blow-out preventer.

Capital expenditures in Argentina for the third quarter of 2010, were $12.3 million ($16.8 million for the nine months ended September 30, 2010). The 2010 Program mainly related to facility construction, the acquisition of seismic data and drilling preparations for a gas well in the Valle Morado block.

The significant elements of our third quarter 2011 Capital Program in Argentina are summarized below:

Puesto Morales / Puesto Morales Este Blocks, Neuquen Basin (100% working interest and operator)

We completed our workover program on 16 wells and, based on successful results, we added two additional workovers in the fourth quarter of 2011.G&G studies are ongoing to optimize the location of four planned development wells expected to be drilled in the fourth quarter of 2011.

Palmar Largo, Noroeste Basin (14% working interest and non-operated)

A development well was completed and workovers continued during the third quarter.

Table Of Contents

Surubi, Noroeste Basin (85% working interest and operator)

Site preparation work for the Proa 2 well continued during the quarter.

Outlook – Argentina

The 2011 capital program in Argentina is $42 million with $33 million allocated to drilling, $4 million to facilities and pipelines, and $5 million to G&G expenditures.

Our planned work program for the fourth quarter of 2011 includes two development wells in each of Puesto Morales and Puesto Morales Este, one development well in Surubi, one development well in Rinconada Sur, three gross wells in Rinconada Norte , workovers in Puesto Morales, facility construction, and geophysical work.

REVIEW OF OPERATIONS IN PERU

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011			2010			% Change		2011			2010			% Change
Segmented Results of Operations - Peru
(Thousands of U.S. Dollars)
Interest	$	6		$	-			-	$	140		$	-			-

Operating expenses	$	80		$	45			82	$	252		$	140			80
DD&A expense		7,375			16			-		40,838			27			-
G&A expenses		946			516			83		2,511			893			181
Foreign exchange loss (gain)		37			14			164		(33	)		22			(250	)
		8,438			591			-		43,568			1,082			-

Segment loss before income taxes	$	(8,432	)	$	(591	)		-	$	(43,428	)	$	(1,082	)		-

Segmented Results of Operations – Peru

Due to the significance of losses before income taxes, Peru became a reportable segment in 2011. The comparative amounts for 2010 were disaggregated from the “All Other” category for presentation purposes.

DD&A expense for the third quarter of 2011 relates to drilling and seismic costs on Block 128. During the quarter, we decided to relinquish our interest in Block 128 and as a result costs associated with this block were written off during the quarter. DD&A expense for the nine months ended September 30, 2011 includes an impairment loss of $40.8 million in our Peru cost center. This impairment loss relates to Peru cost center drilling and seismic costs from dry wells for two blocks, including Block 128.

The increase in G&A expense for the three and nine months ended September 30, 2011 was due to higher salaries and stock based compensation due to expanded operations.

Capital Program – Peru

Capital expenditures in Peru during the third quarter of 2011 were $4.1 million bringing the total expenditures for the nine months ended September 30, 2011 to $29.7 million. Capital expenditures in the third quarter of 2011 included $2.5 million of seismic and environmental costs in Blocks 122, 128, 123, 124 and 129 and environmental monitoring expenses in Block 95.

Capital expenditures in the nine months ended September 30, 2011 included the acquisition of working interests in Blocks 123, 124 and 129, G&G expenditures on these blocks, the drilling of Kanatari -1 on Block 128 and environmental costs in Block 95.

Capital expenditures during the third quarter of 2010 were $7.1 million ($9.2 million for the nine months ended September 30, 2010), mainly related to the acquisition of seismic data and commencement of drilling of Kanatari -1 on Block 128.

Table Of Contents

Outlook - Peru

The 2011 capital program in Peru is $43 million with $18 million allocated to drilling, $1 million to facilities and pipelines and $24 million to G&G expenditures.

Our planned work program for the fourth quarter of 2011 includes:

Blocks 123, 124 and 129, Marañon Basin

Additional infill 2D seismic data is planned to be acquired in late 2011 in Blocks 123 and 129. Documentation for the relinquishment of Block 124 has also been submitted to regulatory authorities for approval.

Block 95, Marañon Basin

A drilling location has been identified for the first exploration well on Block 95, with civil construction initiated in the third quarter of 2011 . Drilling is expected to be undertaken in 2012, pending regulatory approvals.

Block 107 and 133, Marañon Basin

Permitting for drilling on Block 107 is advancing, with drilling expected to begin in the second half of 2012. G&G studies are ongoing on the adjacent Block 133 in preparation for seismic acquisition in 2012.

REVIEW OF CORPORATE ACTIVITIES AND OPERATIONS IN BRAZIL

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			% Change			2011			2010			% Change
Results of Operations - Corporate and Brazil
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	2,161		$	-			-		$	2,494		$	-			-
Interest		95			158			(40	)		367			495			(26	)
		2,256			158			1,328			2,861			495			478

Operating expenses		479			-			-			545			-			-
DD&A expense		1,053			114			824			1,615			269			500
G&A expenses		6,555			5,717			15			22,601			13,807			64
Financial instruments gain		-			-			-			(1,522	)		(44	)		-
Gain on acquisition		-			-			-			(21,699	)		-			-
Foreign exchange loss (gain)		1,558			(981	)		259			1,831			(606	)		402
		9,645			4,850			99			3,371			13,426			(75	)

Loss before income taxes	$	(7,389	)	$	(4,692	)		57		$	(510	)	$	(12,931	)		(96	)

Results of Operations – Corporate Activities and Operations in Brazil

Corporate activities include costs associated with our headquarters in Calgary, Alberta, Canada, and expenses related to technical reviews, business development and compliance and reporting under securities regulations.

Table Of Contents

Oil and natural gas sales represent sales from Block 155 in the onshore Recôncavo Basin of Brazil. We began earning revenue from this block on June 15, 2011, the date regulatory approval was received for the purchase of a 70% participating interest in that block.

DD&A expense for the nine months ending September 30, 2011 primarily relates to production from Block 155 in Brazil.

The increase in G&A expenses for the three and nine months ended September 30, 2011 relates to increased salary and stock based compensation expense and increased consulting charges due to expanded operations in all countries and $1.2 million related to the acquisition of Petrolifera.

Financial instruments gain primarily represents the fair value of warrants issued in connection with the acquisition of Petrolifera. These warrants expired unexercised during August 2011.

The gain on acquisition relates to the acquisition of Petrolifera. The gain reflects the impact on Petrolifera’s pre-acquisition market value of their lack of liquidity and capital resources required to maintain production and reserves and further develop and explore their inventory of prospects.

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

Capital Program – Corporate and Brazil

Capital expenditures in Corporate and Brazil amounted to $7.3 million during the third quarter of 2011 bringing the total expenditures for the nine months ended September 30, 2011 to $37.0 million. Capital expenditures in the third quarter of 2011 included seismic and site preparation expenses and the cost of drilling materials for future wells.

Capital expenditures in the nine months ended September 30, 2011 included $28 million for the acquisition of a 70% participating interest in four blocks in the onshore Recôncavo Basin of Brazil. Expenditures in the comparative periods of 2010 of $6.2 million and $7.5 million, respectively, related to leasehold improvements and the purchase of office furniture and equipment for our headquarters in Calgary and Brazil.

Outlook - Brazil

The 2011 capital program in Brazil is $61 million with $53 million allocated to drilling and acquisitions, $3 million to facilities and pipelines and $5 million to G&G expenditures. Acquisition expenditures include $28 million for the June 2011 acquisition of a 70% participating interest in four blocks in the onshore Recôncavo Basin .

Our planned work program for the fourth quarter of 2011 includes:

Statoil commenced drilling operations on October 1, 2011 on the 1-STAT-7-BAS exploration well. The well is located in the deep water portion of the Camamu Basin at a water depth of 6,250 feet.

Drilling of the 1-GTE-01-BA oil exploration well began on October 7, 2011 and is drilling ahead. The well is located in Block REC-T-142 in the onshore Recôncavo Basin and is expected to reach a total measured depth of approximately 6,070 feet. Upon completion of the well and subsequent evaluation to determine if adequate reservoir is present, a drilling rig is planned to return late in 2011 to drill a horizontal sidetrack from the pilot hole at the optimum depth to test the productivity of the sandstone reservoir target. This will be the first of three horizontal wells we plan to drill in late 2011 and continuing into the first quarter of 2012.

Drilling of the 1-GTE-2-BA oil exploration well is expected to begin in early November, 2011. This well is expected to reach a total measured depth of approximately 6,410 feet and take approximately 30 days to drill.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2011, we had cash and cash equivalents of $226.4 million compared with $355.4 million at December 31, 2010. We believe that our cash position and cash generated from operations will provide us with sufficient liquidity to meet our strategic objectives and 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, we 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 G&A expenses. Under the terms of the facility, we are required to maintain and were in compliance with certain financial and operating covenants. As at September 30, 2011, we had not drawn down any amounts under this facility.

Table Of Contents

As part of the acquisition of Petrolifera, we assumed a reserve backed credit facility with outstanding balance as at the Acquisition Date of $31.3 million. The outstanding balance was repaid when the Argentine restriction preventing its repayment expired on August 5, 2011. The credit facility bore interest at LIBOR plus 8.25% and was partially secured by the pledge of the shares of Petrolifera's subsidiaries.

Cash Flows

During the nine months ended September 30, 2011, our cash and cash equivalents decreased by $129.1 million as net cash provided by operating activities was more than offset by 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 capital expenditures of $248.8 million, partially offset by proceeds on sale of asset backed commercial paper of $22.7 million and $7.7 million cash acquired through the Petrolifera acquisition.

Financing activities included the repayment of $54.1 million of debt acquired through the Petrolifera acquisition, partially offset by $2.6 million related to proceeds from issuance of common shares.

During the nine months ended September 30, 2010, our cash and cash equivalents increased by $37.6 million as cash inflows from operations of $101.4 million and proceeds from issuance of common shares of $22.9 million more than offset cash outflows for capital expenditures of $89.0 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 September 30, 2011, we had no off-balance sheet arrangements.

CONTRACTUAL OBLIGATIONS

We hold four categories of operating leases, namely compressor, office, vehicle and equipment and housing. Future lease payments and other contractual obligations at September 30, 2011 are as follows:

	As at September 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	$	9,436	$	5,612	$	3,239	$	585	$	-
Software and telecommunication		2,017		1,221		754		42		-
Drilling, completion, facility construction and oil transportation services		112,546		80,766		30,153		1,627		-
Consulting		518		518		-		-		-
Total	$	124,517	$	88,117	$	34,146	$	2,254	$	-

Contractual commitments have increased $45.8 million from December 31, 2010 mainly as a result of compressor and other operating equipment leases assumed upon the acquisition of Petrolifera as previously discussed.

Table Of Contents

RELATED PARTY TRANSACTIONS

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 $4,300 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.

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 nine months ended September 30, 2011, $2.2 million was capitalized and at September 30, 2011, $0.1 million was included in accounts payable related to this contract, the terms of which are consistent with market conditions.

On February 1, 2009, we entered into a sublease for office space with a company, of which one of our 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 $8,551 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

For information regarding our critical accounting policies and estimates, see our 2010 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

ITEM 3 - QUAN TITA TIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our principal market risk relates to oil prices. Most 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, 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 $98,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

ITEM 4. - CONTROLS AND PROCE DURES

(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 our disclosure controls and procedures were effective as of September 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.

Table Of Contents

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 September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 September 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 is in one basin in Colombia and two basins in Argentina. 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 in the Noroeste basin 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.

Table Of Contents

Over the years, our profile in Colombia 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.

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.

*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.

In Brazil, there are a number of potential customers for our oil, and we are working to establish relationships with as many as possible to ensure a stable market for our oil. Currently all of our production in Brazil is sold to Petrobras.

*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 $379 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.

*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.

Table Of Contents

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.

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.

Table Of Contents

*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 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.

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. 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.

Exchange rates between the Colombian peso and U.S. dollar have varied between 1,648 pesos to one U.S. dollar to 2,632 pesos to one U.S. dollar since September 1, 2005, a fluctuation of approximately 60%. 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%. Production in Brazil is invoiced and paid in Brazilian Real. The exchange rate of the Brazilian Real has varied between 1.56 Real to one U.S. dollar to 2.45 Real to the U.S. dollar since September 1, 2005, a variance of 57%. A foreign exchange loss of $3.8 million, of which $0.6 million was an unrealized non-cash foreign exchange loss, was recorded for the nine months ended September 30, 2011. The opening and closing U.S. dollar exchange rate

against the Colombian Peso exchange rate was the same.

*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. The Brazilian government has similar regulations in place regarding foreign exchange controls.

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 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.

Table Of Contents

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

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

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

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

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 was 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.

Table Of Contents

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.

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.

Table Of Contents

*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:

●	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.

Table Of Contents

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

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

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

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

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

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

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. 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 nine months ended September 30, 2011, we recorded a ceiling test impairment loss of $40.8 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.

Table Of Contents

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

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

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

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

*Prices and Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate Significantly, Which Could Reduce 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 $95 for the nine months ended September 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. Oil prices in Brazil are defined by contract with the refinery and may be different to 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.

Table Of Contents

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

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

Environmental Risks May Adversely Affect Our Business.

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

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

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, 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.

Table Of Contents

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.

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 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.

Table Of Contents

SIGNATU RES

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

GRAN TIERRA ENERGY INC.

Date: November 8, 2011	/s/ Dana Coffield
	By: Dana Coffield
Its: Chief Executive Officer

Date: November 8, 2011	/s/ Martin Eden
	By: Martin Eden
Its: Chief Financial Officer

Table Of Contents

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	Amended and Restated 2007 Equity Incentive Plan	Filed herewith.

10.2	Executive Employment Agreement dated July 30, 2009 between Gran Tierra Energy Inc. and Duncan Nightingale	Filed herewith

Table Of Contents

10.3	Expatriate Assignment Agreement to Gran Tierra Colombia Ltd., dated December 7, 2010 between Gran Tierra Energy Inc. and Duncan Nightingale	Filed herewith.

10.4	Employment Contract dated January 31, 2011 between Gran Tierra Colombia Ltd. and Duncan Nightingale	Filed herewith

10.5	Amendment to Expatriate Assignment Agreement, dated October 13, 2011 between Gran Tierra Energy Inc. and Duncan Nightingale	Filed herewith.

10.6	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.	Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (SEC File No. 001-34018), filed with the SEC on August 9, 2011.

10.7	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.	Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q (SEC File No. 001-34018), filed with the SEC on August 9, 2011.

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.

TABLE OF CONTENTS

Part I - Financial Information Item 1 - Financial St Ate Ments Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3 - Quan Tita Tive and Qualitative Disclosures About Market Risk Item 4. - Controls and Proce Dures Part II - Other Information Item 1A. Risk Factors Item 6. Exhibits

Exhibits

10.1 Amended and Restated 2007 Equity Incentive Plan Filed herewith. 10.2 Executive Employment Agreement dated July 30, 2009 between Gran Tierra Energy Inc. and Duncan Nightingale Filed herewith 10.3 Expatriate Assignment Agreement to Gran Tierra Colombia Ltd., dated December 7, 2010 between Gran Tierra Energy Inc. and Duncan Nightingale Filed herewith. 10.4 Employment Contract dated January 31, 2011 between Gran Tierra Colombia Ltd. and Duncan Nightingale Filed herewith 10.5 Amendment to Expatriate Assignment Agreement, dated October 13, 2011 between Gran Tierra Energy Inc. and Duncan Nightingale 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 Sept. 30, 2011

Exhibits