GRAN TIERRA ENERGY, INC. (Form: 10-Q, Received: 08/11/2008 15:35:41)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

		FOR THE QUARTERLY PERIOD ENDED June 30, 2008


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

		FOR THE TRANSITION PERIOD FROM __________ TO __________

Commission file number 000-52594

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)


Nevada		98-0479924
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)
300, 611 10 ^th Avenue SW Calgary, Alberta, Canada		T2R 0B2
(Address of principal executive offices)		(Zip code)

(403) 265-3221

(Registrant’s telephone number,

including area code)

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

Indicate by check mark whether the registrant 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 o	Accelerated Filer x
Non-Accelerated Filer o	(do not check if a smaller reporting company) Smaller Reporting Company o

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

On August 1, 2008, the total number of outstanding shares of the registrant’s common stock and outstanding exchangeable shares of Gran Tierra Goldstrike Inc., which are exchangeable into the registrant’s common stock, was 114,813,401. Of this total, there were 103,829,275 shares of the registrant’s common stock outstanding and 10,984,126 shares of common stock issuable upon the exchange of exchangeable shares. In addition, the registrant had outstanding one share of special voting stock, through which the holders of exchangeable shares may exercise their voting rights with respect to Gran Tierra Energy Inc. The special voting stock generally votes together with the common stock on all matters on which the holders of the registrant’s common stock are entitled to vote. The trustee holder of the share of special voting stock has the right to cast a number of votes equal to the number of then outstanding exchangeable shares.

TABLE OF CONTENTS

		Page
	PART I - FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	3

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30

ITEM 4.	CONTROLS AND PROCEDURES	31

ITEM 4T.	CONTROLS AND PROCEDURES	32

	PART II - OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	32

ITEM 1A.	RISK FACTORS	32

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

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	43

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS	43

ITEM 5.	OTHER INFORMATION	44

ITEM 6.	EXHIBITS	44

SIGNATURES		44

EXHIBIT INDEX		45

PART I - FINANCIAL INFORMATION

ITEM 1 - FINANCIAL STATEMENTS

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations and Accumulated Deficit (Unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007

REVENUE AND OTHER INCOME
Oil and natural gas sales	$	33,042		$	3,611		$	53,791		$	7,935
Interest		102			139			172			332
		33,144			3,750			53,963			8,267
EXPENSES
Operating		3,726			1,925			6,253			4,106
Depletion, depreciation and accretion		5,400			2,377			8,464			4,701
General and administrative		4,641			2,680			8,774			4,619
Liquidated damages (Note 5)		-			3,235			-			7,367
Derivative financial instruments (Note 10)		6,278			20			7,462			677
Foreign exchange gain		(397	)		(239	)		(383	)		(7	)
		19,648			9,998			30,570			21,463

INCOME (LOSS) BEFORE INCOME TAXES		13,496			(6,248	)		23,393			(13,196	)

INCOME TAX (EXPENSES) RECOVERIES (Note 7)		(4,970	)		1,176			(10,191	)		1,474

NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)		8,526			(5,072	)		13,202			(11,722	)

ACCUMULATED DEFICIT, BEGINNING OF PERIOD		(11,835	)		(14,694	)		(16,511	)		(8,044	)

ACCUMULATED DEFICIT, END OF PERIOD	$	(3,309	)	$	(19,766	)	$	(3,309	)	$	(19,766	)

NET INCOME (LOSS) PER COMMON SHARE - BASIC	$	*0.08*		$	(0.05	)	$	*0.13*		$	(0.12	)
NET INCOME (LOSS) PER COMMON SHARE - DILUTED	$	*0.07*		$	(0.05	)	$	*0.11*		$	(0.12	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC		*105,123,188*			95,205,518			*101,054,083*			95,329,950
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING – DILUTED (Note 5)		*123,979,074*			95,205,518			*119,136,907*			95,329,950

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(Thousands of U.S. Dollars)

	June 30,			December 31,
	2008			2007

ASSETS
Current Assets
Cash and cash equivalents	$	35,303		$	18,189
Accounts receivable		39,157			10,695
Inventory		628			787
Taxes receivable		1,272			1,177
Prepaids		486			442
Deferred tax asset (Note 7)		1,148			220
Total Current Assets		77,994			31,510
Oil and Gas Properties (using the full cost method of accounting)
Proved		50,116			44,292
Unproved		21,655			18,910
Total Oil and Gas Properties		71,771			63,202
Other Assets		1,593			716
Total Property, Plant and Equipment (Note 4)		73,364			63,918
Long Term Assets
Deferred tax asset (Note 7)		684			1,839
Taxes receivable		560			525
Goodwill		15,005			15,005
Total Long Term Assets		16,249			17,369
Total Assets	$	167,607		$	112,797

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable (Note 8)	$	13,307		$	11,327
Accrued liabilities (Note 8)		13,825			6,139
Derivative financial instruments (Note 10)		5,540			1,594
Current taxes payable		12,843			3,284
Deferred tax liability (Note 7)		810			1,108
Total Current Liabilities		46,325			23,452
Long term liabilities		115			132
Deferred tax liability (Note 7)		8,510			9,235
Deferred remittance tax (Note 7)		1,262			1,332
Derivative financial instruments (Note 10)		2,879			1,055
Asset retirement obligation (Note 6)		938			799
Total Long Term Liabilities		13,704			12,553
Shareholders’ Equity
Common shares (Note 5)		218			95
(99,582,314 and 80,389,676 common shares and 11,192,859 and 14,787,303 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2008 and December 31, 2007, respectively)
Additional paid-in capital		99,807			72,458
Warrants		10,862			20,750
Accumulated deficit		(3,309	)		(16,511	)
Total Shareholders’ Equity		107,578			76,792
Total Liabilities and Shareholders’ Equity	$	167,607		$	112,797

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Six Month Ended June 30,
	2008			2007

				(restated – see Note 2)
OPERATING ACTIVITIES
Net income (loss)	$	13,202		$	(11,722	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		8,464			4,701
Deferred taxes		(866	)		1,446
Stock based compensation		847			386
Liquidated damages		-			7,367
Unrealized loss on derivative financial instruments		5,770			677
Net changes in non-cash working capital:
Accounts receivable		(28,462	)		(171	)
Inventory		159			228
Prepaids and other current assets		(44	)		342
Liquidated damages		-			(1,528	)
Accounts payable and accrued liabilities		3,888			(1,433	)
Taxes receivable and payable		9,464			(3,982	)
Net cash provided by (used in) operating activities		12,422			(3,689	)

INVESTING ACTIVITIES
Restricted cash		-			1,010
Oil and gas property expenditures		(11,712	)		(10,998	)
Long term assets and liabilities		(52	)		(581	)
Net cash used in investing activities		(11,764	)		(10,569	)

FINANCING ACTIVITIES
Proceeds from issuance of common stock		16,456			-
Net cash provided by financing activities		16,456			-

Net increase (decrease) in cash and cash equivalents		17,114			(14,258	)
Cash and cash equivalents, beginning of period		18,189			24,101
Cash and cash equivalents, end of period	$	35,303		$	9,843

Non-cash investing activities:
Non-cash working capital related to capital additions	$	*14,037*		$	6,400

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended			Year Ended
	June 30, 2008			December 31, 2007

SHARE CAPITAL
Balance beginning of period	$	95		$	95
Issue of common shares		123			1
Cancelled common shares		-			(1	)
Balance end of period		218			95

ADDITIONAL PAID-IN CAPITAL
Balance beginning of period		72,458			71,311
Cancelled common shares		-			(1,086	)
Issue of common shares		16,275			719
Exercise of warrants		9,888			513
Exercise of stock options		58			-
Stock based compensation expense		1,128			1,001
Balance end of period		99,807			72,458

WARRANTS
Balance beginning of period		20,750			12,832
Cancelled warrants		-			(233	)
Issue of warrants		-			8,625
Exercise of warrants		(9,888	)		(474	)
Balance end of period		10,862			20,750

ACCUMULATED DEFICIT
Balance beginning of period		(16,511	)		(8,044	)
Net income (loss)		13,202			(8,467	)
Balance end of period		(3,309	)		(16,511	)

TOTAL SHAREHOLDERS' EQUITY	$	107,578		$	76,792

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

1. Description of Business

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

2. Significant Accounting Policies

These interim unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the interim consolidated financial statements, and revenues and expenses during the reporting period. In the opinion of the Company’s management, all adjustments (all of which are normal and recurring) that have been made are necessary to fairly state the consolidated financial position of the Company and its subsidiaries as at June 30, 2008 and December 31, 2007, the results of its operations for the three and six month periods ended June 30, 2008 and 2007, and its cash flows for the six month periods ended June 30, 2008 and 2007.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim consolidated financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2007 included in the Company’s 2007 Annual Report on Form 10-K/A, filed with the Securities Exchange Commission on May 12, 2008. The Company’s significant accounting policies are described in note 2 of the consolidated financial statements which are included in the Company’s 2007 Annual Report on Form 10-K/A.

Inventory

Crude oil inventories at June 30, 2008 and December 31, 2007 are $0.5 million and $0.4 million, respectively. Supplies at June 30, 2008 and December 31, 2007 are $0.1 million and $0.4 million, respectively.

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value under US GAAP and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB FSP 157-2 which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. These nonfinancial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test, asset retirement obligations and nonfinancial assets acquired and liabilities assumed in a business combination. Effective January 1, 2008, the Company adopted SFAS 157 for financial assets and liabilities. The partial adoption of SFAS 157 for financial assets and liabilities did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows. See Note 10 for information and related disclosures.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS 159 permits an entity to elect fair value as the initial and subsequent measurement attribute for many financial assets and liabilities. Entities electing the fair value option would be required to recognize changes in fair value in earnings. Entities electing the fair value option are required to distinguish on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. SFAS 159 is effective for the Company’s fiscal year 2008 and was adopted January 1, 2008. The adjustment to reflect the difference between the fair value and the carrying amount would be accounted for as a cumulative-effect adjustment to retained earnings as of the date of initial adoption. The adoption of SFAS 159 on January 1, 2008 did not impact the Company’s consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS 141 (R), “Business Combinations”, and SFAS 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS 141 (R) requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141 (R) and SFAS 160 are effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption is prohibited and the provisions are applied prospectively. The Company has not yet determined the effect on the Company’s consolidated financial statements, if any, upon adoption of SFAS 141 (R) or SFAS No. 160.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities”. SFAS 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities and how derivative instruments and related hedged items affect a company's financial position, financial performance and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact, if any, that SFAS 161 will have on its consolidated financial statements.

In May 2008, the FASB issued SFAS 163, “Accounting for Financial Guarantee Insurance Contracts – An interpretation of FASB Statement No. 60”. SFAS 163 requires that an insurance enterprise recognize a claim liability prior to an event of default when there is evidence that credit deterioration has occurred in an insured financial obligation. It also clarifies how SFAS 60 applies to financial guarantee insurance contracts, including the recognition and measurement to be used to account for premium revenue and claim liabilities, and requires expanded disclosures about financial guarantee insurance contracts. It is effective for financial statements issued for fiscal years beginning after December 15, 2008, except for some disclosures about the insurance enterprise’s risk-management activities. SFAS 163 requires that disclosures about the risk-management activities of the insurance enterprise be effective for the first period beginning after issuance. Except for those disclosures, earlier application is not permitted. The adoption of this statement is not expected to have a material effect on the Company’s consolidated financial statements.

In May 2008, the FASB issued SFAS 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. It is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. The adoption of this statement is not expected to have a material effect on the Company’s consolidated financial statements.

Restatement of Prior Year Financial Statements

Subsequent to the release of financial statements for the year ended December 31, 2007 the Company determined that $3.7 million of changes in accounts payable and accrued liabilities, initially attributed to net cash provided by (used in) operating activities should have been attributed to oil and gas property expenditures and net cash used in investing activities (see Note 8). Accordingly, line items in the statements of cash flows for the six month period ended June 30, 2007 have been restated.

Net changes in non-cash working capital related to accounts payable and accrued liabilities attributable to operating activities for the six month period ended June 30, 2007 have been restated to a decrease of $1.4 million from an increase of $3.5 million, and net cash provided by (used in) operating activities has been restated to a use of $3.7 million from $1.3 million cash flow provided by operating activities. For the six months ended June 30, 2007, the change in non-cash working capital related to capital additions has been restated to a decrease of $1.6 million from a decrease of $6.6 million, cash used for oil and gas property expenditures (including the change in non-cash working capital related to capital additions) has been restated to $11.0 million from $16.0 million and net cash used in investing activities has been restated to $10.6 million from $15.5 million.

The preceding restatement has no effect on the net increase or decrease in cash or cash equivalents for any period.

3. Segment and Geographic Reporting

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

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

	Three Months Ended June 30, 2008
(Thousands of U.S. Dollars)		Corporate			Colombia			Argentina			Total
Oil and natural gas sales	$	-		$	30,793		$	2,249		$	33,042
Interest income		18			79			5			102
Depreciation, depletion and accretion		31			4,813			556			5,400
Segment income (loss) before income tax		(9,113	)		22,575			34			13,496
Segment capital expenditures	$	1,504		$	5,000		$	2,114		$	8,618

	Three Months Ended June 30, 2007
		Corporate			Colombia			Argentina			Total
Oil and natural gas sales	$	-		$	1,965		$	1,646		$	3,611
Interest income		64			43			32			139
Depreciation, depletion and accretion		27			1,720			630			2,377
Segment loss before income tax		(5,089	)		(826	)		(333	)		(6,248	)
Segment capital expenditures	$	88		$	4,398		$	(255	)	$	4,231

	Six Months Ended June 30, 2008
		Corporate			Colombia			Argentina			Total
Oil and natural gas sales	$	-		$	50,158		$	3,633		$	53,791
Interest income		21			141			10			172
Depreciation, depletion and accretion		61			7,280			1,123			8,464
Segment income (loss) before income tax		(12,810	)		36,842			(639	)		23,393
Segment capital expenditures	$	2,093		$	13,149		$	2,530		$	17,772

	Six Months Ended June 30, 2007
		Corporate			Colombia			Argentina			Total
Oil and natural gas sales	$	-		$	4,153		$	3,782		$	7,935
Interest income		163			137			32			332
Depreciation, depletion and accretion		52			3,544			1,105			4,701
Segment loss before income tax		(11,064	)		(1,256	)		(876	)		(13,196	)
Segment capital expenditures	$	527		$	8,225		$	620		$	9,372

	As at June 30, 2008
		Corporate			Colombia			Argentina			Total
Property, plant and equipment	$	3,062		$	49,631		$	20,671		$	73,364
Goodwill		-			15,005			-			15,005
Other assets		25,881			43,906			9,451			79,238
Total	$	28,943		$	108,542		$	30,122		$	167,607

	As at December 31, 2007
		Corporate		Colombia		Argentina		Total
Property, plant and equipment	$	1,031	$	43,639	$	19,248	$	63,918
Goodwill		-		15,005		-		15,005
Other assets		11,303		15,949		6,622		33,874
Total	$	12,334	$	74,593	$	25,870	$	112,797

The Company’s revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. In 2008, the Company has one significant customer for its Colombian crude oil, Ecoptrol S.A., a Colombian government agency. In Argentina, the Company has one significant customer, Refineria del Norte S.A.

4. Property, Plant and Equipment

	As at June 30, 2008							As at December 31, 2007
(Thousands of U.S. Dollars)			Accumulated			Net Book				Accumulated			Net Book
	Cost		DD&A			Value		Cost		DD&A			Value
Oil and natural gas properties
Proved	$	71,908	$	(21,792	)	$	50,116	$	57,832	$	(13,540	)	$	44,292
Unproved		21,655		-			21,655		18,910		-			18,910
		93,563		(21,792	)		71,771		76,742		(13,540	)		63,202
Furniture, fixtures and leasehold improvements		1,533		(615	)		918		815		(560	)		255
Computer equipment		993		(423	)		570		719		(299	)		420
Automobiles		150		(45	)		105		72		(31	)		41
Total Property, Plant and Equipment	$	96,239	$	(22,875	)	$	73,364	$	78,348	$	(14,430	)	$	63,918

For the six months ended June 30, 2008, the Company had capitalized in the Colombian full cost center $0.7 million (December 31, 2007 - $1.7 million) of general and administrative expenses including $0.2 million (December 31, 2007 - $0.1 million) of stock-based compensation expense. Also included is $0.3 million (December 31, 2007 - $0.2 million) of general and administrative expenses in the Argentina full cost center which includes $0.1 million (December 31, 2007 - $0.1 million) of stock-based compensation.

The unproven oil and natural gas properties at June 30, 2008 consist of exploration lands held in Colombia, Argentina and Peru. The Company had $13.9 million (December 31, 2007 - $15.1 million) in unproved assets in Colombia, $5.2 million (December 31, 2007 - $3.1 million) of unproved assets in Argentina and $2.6 million (December 31, 2007 - $0.7 million) of unproved assets in Peru. These properties are being held for their exploration potential and are not being depleted pending determination of the existence of proved reserves. Gran Tierra Energy will continue to assess and allocate the unproven properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.

5. Share Capital

The Company’s authorized share capital consists of 325,000,001 shares of capital stock, of which 300 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 1 share is designated as special voting stock, par value $0.001 per share. Outstanding share capital at June 30, 2008, consists of 99,582,314 common voting shares of the Company and 11,192,859 exchangeable shares of Goldstrike Exchange Co., a wholly-owned subsidiary of Gran Tierra Energy. Each exchangeable share is exchangeable only into one common voting share of the Company. The holders of common stock are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the 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 the same rights as holders of common voting shares.

Warrants

As at June 30, 2008, the Company had two remaining issues of warrants outstanding: 9,362,734 warrants outstanding to purchase 4,681,367 common shares at an exercise price of $1.25 per share expiring between August 2010 and January 2011; and 27,475,000 warrants outstanding to purchase 13,737,500 common shares at an exercise price of $1.05 per share expiring June 2012. For the six months ended June 30, 2008, 15,409,031 common shares were issued upon the exercise of 30,997,339 warrants (six months ended June 30, 2007 – nil).

Registration Rights Payments

The shares and warrants have registration rights associated with their issuance pursuant to which the Company agreed to register for resale the shares and warrants. In the event that the registration statements were not declared effective by the United States Securities and Exchange Commission (“SEC”) by specified dates, the Company was required to pay liquidated damages to the purchasers of the shares and warrants.

In June 2006, the Company sold an aggregate of 50 million units of its securities at a price of $1.50 per unit in a private offering for gross proceeds of $75 million, pursuant to three separate Securities Purchase Agreements, dated June 20, 2006, and one Securities Purchase Agreement, dated June 30, 2006 (collectively, the “2006 Offering”). Each unit comprised one share of Gran Tierra Energy’s common stock and one warrant to purchase one-half of a share of Gran Tierra Energy’s common stock at an exercise price of $1.75 exercisable for a period of five years, resulting in the issuance of 50 million shares of Gran Tierra Energy’s common stock. In connection with the issuance of these securities, Gran Tierra Energy entered into four separate Registration Rights Agreements with the investors pursuant to which Gran Tierra Energy agreed to register for resale the shares and warrants (and shares issuable pursuant to the warrants) issued to the investors in the offering by November 17, 2006. The second registration statement was declared effective by the SEC on May 14, 2007 at which time the Company had accrued $8.6 million in liquidated damages. On June 27, 2007, under the terms of the Registration Rights Agreements, the Company obtained a sufficient number of consents from the signatories to the agreements waiving Gran Tierra Energy’s obligation to pay in cash the accrued liquidated damages. The Company agreed to amend the terms of the warrants issued in the 2006 Offering by reducing the exercise price of the warrants to $1.05 and extending the life of the warrants by one year, in lieu of a cash payment for liquidated damages. The $8.6 million of liquidated damages had been recorded as an expense in the consolidated statement of operations in the amounts of $7.4 million during the six months ended June 30, 2007, and $1.2 million in the fourth quarter of 2006 and had been reflected on the consolidated balance sheet as an increase to the warrant value included in shareholders’ equity and a settlement of the liability for liquidated damages.

Stock Options

As of June 30, 2008, the Company has a 2007 Equity Incentive Plan, formed through the approval by shareholders of the amendment and restatement of the 2005 Equity Incentive Plan, under which the Company’s board of directors is authorized to issue options or other rights to acquire up to 9,000,000 shares of the Company’s common stock.

The Company had granted options to purchase common shares to certain directors, officers, employees and consultants. Each option permits the holder to purchase one common share at the stated exercise price. The options vest over three years and have a term of ten years, or the grantees end of service to the Company, whichever occurs first. At the time of grant, the exercise price equals the market price. For the six months ended June 30, 2008, 189,164 common shares were issued upon the exercise of 189,164 stock options (six months ended June 30, 2007 – nil). The following options are outstanding as of June 30, 2008:

	Number of			Weighted Average
	Outstanding			Exercise Price
	Options			$/Option
Outstanding, December 31, 2007		5,724,168		$	1.52
Granted in 2008		300,000			4.92
Exercised in 2008		(189,164	)		(0.87	)
Forfeited in 2008		(205,003	)		(1.71	)
Outstanding, June 30, 2008		5,630,001		$	1.71

The weighted average grant date fair value for options granted in 2008 was $2.85.

The table below summarizes stock options outstanding at June 30, 2008:

	Number of		Weighted Average		Weighted
	Outstanding		Exercise Price		Average
Range of exercise prices ($/option)	Options		$/Option		Expiry Years
0.80		1,137,502	$	0.80		7.4
1.19 to 1.29		1,779,999		1.26		8.5
1.72		385,000		1.72		9.4
2.14		2,027,500		2.14		9.5
3.5 to 7.75		300,000		4.92		9.8
Total		5,630,001	$	1.71		8.74

The aggregate intrinsic value of options outstanding at June 30, 2008 is $35.2 million based on the Company’s closing stock price of $7.97 for that date. At June 30, 2008, there was $2.5 million of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next three years.

For the six months ended June 30, 2008, the stock-based compensation expense was $1.1 million (six months ended June 30, 2007 - $0.4 million) of which $0.7 million (six months ended June 30, 2007 - $0.4 million) had been recorded in general and administrative expense and $0.1 million had been recorded in operating expense in the consolidated statement of operations (six months ended June 30, 2007 – nil). For the six months ended June 30, 2008, $0.3 million was capitalized as part of exploration and development costs (six months ended June 30, 2007 – nil).

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Dividend yield ($ per share)	$	-	$	-	$	-	$	-
Volatility (%)		89		101		75 to 92		101 to 104
Risk-free interest rate (%)		2.1		4.6		2.1		4.6 to 4.8
Expected term (years)		3		3		3		3
Forfeiture percentage (% per year)		10		10		10		10

Weighted average shares outstanding

	Three Months Ended June 30,			Six Months Ended June 30,
	2008			2008
Weighted average number of common shares outstanding		105,123,188			101,054,083
Shares issuable pursuant to warrants		15,210,626			14,628,945
Shares issuable pursuant to stock options		4,005,942			3,729,618
Shares to be purchased from proceeds of stock options and warrants		(360,682	)		(275,739	)
Weighted average number of diluted common shares outstanding		123,979,074			119,136,907

Income (loss) per share

For the three and six month periods ended June 30, 2008, options to purchase 100,000 common shares were excluded from the diluted income per share calculation as the instruments were anti-dilutive. For the three and six month periods ended June 30, 2007, options to purchase 3,450,000 common shares and 68,864,978 warrants to purchase 34,432,489 common shares were excluded from the diluted loss per share calculation as the instruments were anti-dilutive.

6. Asset Retirement Obligation

Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and gas properties are as follows:

	Six Months Ended		Year Ended
(Thousands of U.S. Dollars)	June 30, 2008		December 31, 2007
Balance, beginning of period	$	799	$	595
Liability incurred		106		154
Foreign exchange		14		19
Accretion		19		31
Balance, end of period	$	938	$	799

7. Income Taxes

The Company had accumulated losses of approximately $25.1 million as at June 30, 2008 that can be carried forward and applied against future taxable income. A valuation allowance of $6.5 million had been taken for the potential income tax benefit associated with the losses incurred by the Company, due to uncertainty of utilization of the tax losses.

The income tax (expenses) recoveries reported differs from the amount computed by applying the statutory rate to income (loss) before income taxes for the following reasons:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2008			2007
Income (loss) before income taxes	$	23,393		$	(13,196	)
		29.5	%		34	%
Income tax benefit expected		(6,901	)		4,487
Benefit of tax losses not recognized		(19	)		(2,627	)
Impact of tax rate changes on deferred tax balances		-			-
Impact of foreign taxes		(565	)		-
Enhanced tax depreciation incentive		1,240			-
Stock-based compensation		(159	)		(386	)
U.S. Partnership income pick-up		(12,894	)		-
Utilization of foreign tax credits		10,073			-
Non-deductible items		(77	)		-
Previously unrecognized tax assets		(889	)		-
Total income tax (expense) recovery	$	(10,191	)	$	1,474

Deferred tax assets and liabilities consist of the following:

(Thousands of U.S. Dollars)	June 30, 2008			December 31, 2007
Deferred Tax Assets
Tax benefit of loss carry forwards	$	3,284		$	4,935
Book value in excess of tax basis		421			75
Foreign tax credits and other accruals		973			733
Capital losses		3,676			1,063
Deferred tax assets before valuation allowance		8,354			6,806
Valuation allowance		(6,522	)		(4,747	)
	$	1,832		$	2,059
Deferred Tax Assets
Current	$	1,148		$	220
Long-term		684			1,839
	$	1,832		$	2,059

Deferred Tax Liabilities
Book value in excess of tax basis
Current	$	(810	)	$	(1,108	)
Long-term		(8,510	)		(9,235	)
	$	(9,320	)	$	(10,343	)

Net Deferred Tax Liabilities	$	(7,488	)	$	(8,284	)

The Company calculated a deferred remittance tax in Colombia based on 7% of profits which are not reinvested in the business on the presumption that such profits would be transferred to the foreign owners up to December 31, 2006. As of January 1, 2007, the Colombian government rescinded this law; therefore, no further remittance tax liabilities will be accrued. The historical balance which was included on the Company’s financial statements as of June 30, 2008 is $1.3 million (December 31, 2007 – $1.3 million).

The Company had accrued no amounts as of June 30, 2008 and December 31, 2007, for the potential payment of interest and penalties. For the three and six month periods ended June 30, 2008 and June 30, 2007, the Company had not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions. The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and other Canadian and foreign jurisdictions. The Company is subject to income tax examinations for the calendar tax years ended 2005 through 2007 in all jurisdictions and also for the calendar tax year ending 2004 for the U.S. federal jurisdiction

As at June 30, 2008, the Company had deferred tax assets relating to net operating loss carry forwards of $14.6 million (December 31, 2007 - $15.8 million) and had capital losses of $10.5 million (December 31, 2007 - $3.0 million) before valuation allowances. Of these losses, $14.6 million (December 31, 2007 - $9.4 million) are losses generated by the foreign subsidiaries of the Company. Of the total losses, $10.5 million (December 31, 2007 - $4.0 million) will begin to expire by 2011 and $14.6 million of net operating losses (December 31, 2007 - $11.9 million) will begin to expire thereafter.

8. Accounts Payable and Accrued Liabilities

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

As at June 30, 2008

(Thousands of U.S. Dollars)

Corporate

Colombia

Argentina

Total

Capital

1,003

11,516

1,518

14,037

Payroll

252

661

936

Audit, legal and consultants

1,109

1,165

General and administrative

1,461

277

195

1,933

Operating

8,190

871

9,061

Total

3,825

20,644

2,663

27,132

	As at December 31, 2007
	(restated - see Note 2)
(Thousands of U.S. Dollars)	Corporate		Colombia		Argentina		Total
Capital	$	51	$	7,985	$	223	$	8,259
Payroll		476		513		212		1,201
Audit, legal and consultants		1,385		196		105		1,686
General and administrative		319		299		73		691
Operating		-		4,898		731		5,629
Total	$	2,231	$	13,891	$	1,344	$	17,466

9. Commitments and Contingencies

Leases

Gran Tierra Energy holds four categories of operating leases: office, compressor, vehicle and housing. Future lease payments at June 30, 2008 are as follows:

Year (Thousands of U.S. Dollars)	Cost
2008, Remainder	$	440
2009		655
2010		576
2011		276
2012		281
2013		23
Total lease payments	$	2,251

The Company had contracted with a third party to provide catering services for its field operations in Colombia. The contract ends January 14, 2009. The remaining contractual commitment is $0.1 million to be incurred evenly over the remaining duration of the contract.

The Company had contracted with a third party to provide a helicopter for field transportation for its Colombia field operations. The contract ends September 30, 2008. The minimum obligation under the contract is for 30 flight hours per month at a rate of $880 per hour. The remaining obligation is $0.1 million.

Guarantees

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company had purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated.

The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid. Management believes the resolution of these matters would not have a material adverse impact on the Company’s liquidity, consolidated financial position or results of operations.

Contingencies

Ecopetrol and Gran Tierra 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 the Clause 3.5 of Attachment-B of the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for benefit of Ecopetrol. There has been no agreement between the parties, and Ecopetrol has filed a lawsuit in the Contravention Administrative Court in the District of Cauca regarding this matter. Gran Tierra Colombia filed a response on April 29, 2008 in which it refuted all of Ecopetrol’s claims and requested a change of venue to the courts in 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 $5.8 million, which possible loss is shared 50% with Gran Tierra Colombia’s partner Solana Petroleum Exploration (Colombia) S.A., with the remaining 50% the responsibility of Gran Tierra Colombia. To the Company’s knowledge, there are no other legal proceedings against Gran Tierra Energy.

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

The Company recognizes the fair value of its derivative instruments as assets or liabilities on the balance sheet. None of the Company's derivative instruments currently qualify as fair value hedges or cash flow hedges, and accordingly, changes in fair value of the derivative instruments are recognized as income or expense in the consolidated statement of operations and accumulated deficit with a corresponding adjustment to the fair value of derivative instruments recorded on the balance sheet. Under the terms of the Credit Facility with Standard Bank (Note 11), the Company was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. In accordance with the terms of the Facility, the Company entered into a costless collar derivative instrument for crude oil based on West Texas Intermediate (“WTI”) price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period ending February 2010, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010.

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2008		2007		2008		2007
Financial Derivative Loss
Realized financial derivative loss	$	1,201	$	-	$	1,692	$	-
Unrealized financial derivative loss		5,077		20		5,770		677
Total financial derivative loss	$	6,278	$	20	$	7,462	$	677

Certain of Gran Tierra Energy’s assets and liabilities are reported at fair value in the accompanying balance sheets. The following tables provide fair value measurement information for such assets and liabilities as of June 30, 2008 and December 31, 2007.

The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at June 30, 2008 and December 31, 2007. These assets and liabilities are not presented in the following tables.

As at June 30, 2008

Fair Value Measurements Using:

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Carrying

Total Fair

Markets

Inputs

Amount

Value

(Level 1)

(Level 2)

(Level 3)

Financial Assets (Liabilities)

(Thousands of U.S. Dollars)

Crude oil collars

(8,419

)

(8,419

)

—

(8,419

)

—

As at December 31, 2007

Fair Value Measurements Using:

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Carrying

Total Fair

Markets

Inputs

Amount

Value

(Level 1)

(Level 2)

(Level 3)

Financial Assets (Liabilities)

(Thousands of U.S. Dollars)

Crude oil collars

(2,649

)

(2,649

)

—

(2,649

)

—

SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. When available, Gran Tierra Energy measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

The Company uses Level 2 method to measure the fair value of its crude oil collars. The fair values of the crude oil are estimated using internal discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements. The Company does not have any other assets or liabilities whose fair value is measured using Level 1 or 3 methods.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements

The Company does not have any assets or liabilities whose fair value is measured using this method.

Level 2 Fair Value Measurements

Crude oil collars — The fair values of the crude oil are estimated using internal discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements.

Level 3 Fair Value Measurements

The Company does not have any financial assets or financial liabilities whose fair value is measured using this method.

11. Credit Facility

On February 28, 2007, the Company entered into a Credit Facility with Standard Bank Plc. The Facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of the Company’s petroleum reserves up to maximum of $50 million. The initial borrowing base is $7 million based on the mid-year 2006 Independent Reserves Evaluation report and the borrowing base will be re-determined semi-annually based on reserve evaluation reports. Based on Standard Bank Plc’s mid-year 2007 Independent Reserve Audit, the Company has received preliminary approval to increase its borrowing base to $20 million. The Facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the Facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base and is included in general and administrative expense. The Facility is secured primarily on the Company’s Colombian assets. The Company was required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. Under the terms of the Facility, the Company is required to maintain compliance with specified financial and operating covenants. As at June 30, 2008, the Company had not drawn-down on this facility.

12. Subsequent Event

On July 29, 2008, the Company announced that it had entered into a definitive agreement providing for the business combination of Gran Tierra Energy and Solana Resources Limited (“Solana”). Under the terms of the Agreement, each Solana shareholder will receive either (i) 0.9527918 of a common share of Gran Tierra Energy or; (ii) 0.9527918 of a common share of a Canadian subsidiary of Gran Tierra Energy (an “Exchangeable Share”) for each common share of Solana held, which represents a premium of approximately 14.1 % to the 20 day weighted average trading price to July 28, 2008 of the Solana shares on the TSX Venture Exchange and Gran Tierra Energy’s July 28, 2008, closing price on the Toronto Stock Exchange of CAD $5.73. The shares of the Canadian subsidiary of Gran Tierra Energy: (i) will have the same voting rights, dividend entitlements and other attributes as Gran Tierra Energy common stock; (ii) will be exchangeable, at each shareholder’s option, on a one-for-one basis, into Gran Tierra Energy common stock; and (iii) subject to compliance with the listing requirements of the Toronto Stock Exchange, will be listed on the Toronto Stock Exchange. The Exchangeable Shares will automatically be exchanged for Gran Tierra Energy common stock five years from closing, and in certain other events.

The transaction will be completed pursuant to a statutory plan of arrangement pursuant to the Business Corporations Act (Alberta). Upon completion of the transaction, Solana will become an indirect wholly-owned subsidiary of Gran Tierra Energy. On a diluted basis, upon the closing of the plan of arrangement, Solana securityholders will own approximately 49% of the combined company and Gran Tierra Energy securityholders will own approximately 51% of the combined company.

The proposed transaction is subject to regulatory, stock exchange, court and shareholder approvals. Gran Tierra Energy and Solana expect to hold shareholder meetings in October 2008. A joint proxy statement and management information circular is expected to be mailed to shareholders of the companies in September 2008. The parties have agreed to pay each other a termination fee of $21 million in certain circumstances and an expense reimbursement fee of $1.5 million in certain other circumstances.

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

Statement Regarding Forward-Looking Information

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

Overview

We are an independent international energy company involved in oil and natural gas exploration, development and production. We plan to continually increase our oil and natural gas reserves through a balanced strategy of exploration drilling, development and acquisitions in South America. Initial countries of interest are Argentina, Colombia and Peru.

We took our current form on November 10, 2005 when the former Gran Tierra Energy Inc., a privately-held Alberta corporation, which we refer to as Gran Tierra Canada, was acquired by an indirect subsidiary of Goldstrike Inc, a Nevada corporation. Goldstrike adopted the assets, management, business operations, business plan and name of Gran Tierra Canada. For accounting purposes, the predecessor company in the transaction was the former Gran Tierra Canada, and the financial information of the former Goldstrike was eliminated at consolidation. This transaction is accounted for as a reverse takeover of Goldstrike Inc. by Gran Tierra Canada.

Prior to September 1, 2005, we had no oil and gas interests or properties. In September 2005 and during 2006 we acquired oil and gas interests and properties in Argentina, Colombia and Peru. We funded acquisitions of our properties in Colombia and Argentina through a series of private placements of our securities that occurred between September 2005 and February 2006 and an additional private placement that occurred in June 2006.

Financial and Operational Highlights

	Three Months Ended June 30 ,					%		Six Months Ended June 30 ,					%
	2008		2007			*Change*		2008		2007			*Change*

Production - Barrels of Oil Equivalent per Day (“boe”)		3,399		1,021			233		3,121		1,140			174

Barrels of Oil Equivalent Prices Realized	$	106.80	$	38.85			175	$	94.69	$	38.24			148

Revenue and Interest (Thousands of U.S. Dollars)	$	33,144	$	3,750			784	$	53,963	$	8,267			553

Net Income (Loss) (Thousands of U.S. Dollars)	$	8,526	$	(5,072	)		-	$	13,202	$	(11,722	)		-

Net Income (Loss) Per Share, Basic	$	0.08	$	(0.05	)		-	$	0.13	$	(0.12	)		-

Capital Expenditures (Thousands of U.S. Dollars)	$	8,618	$	4,231			104	$	17,772	$	9,372			90

Financial Highlights for Three Months Ended June 30, 2008

Net income for the three months ended June 30, 2008 amounted to $8.5 million compared to a net loss of $5.1 million recorded for the same period last year. A 233% increase in production of crude oil and natural gas, net of royalties, coupled with a 175% improvement in the net realized price of crude oil contributed to the increase in net income. On a basic income per share basis, we recorded $0.08 for the current quarter compared to a net loss of $0.05 per share for the same quarter last year.

·	Increased production levels as well as improved crude oil prices resulted in a 784% increase in revenues and interest with the majority of the increase coming from our Colombian operations.

·	Capital expenditures for the current quarter amounted to $8.6 million, an increase of 104% compared to the same period last year. The increase resulted from higher activity levels in all business units.

Financial Highlights for Six Months Ended June 30, 2008

Net income for the six months ended June 30, 2008 amounted to $13.2 million ($0.13 income per share), a substantial turnaround from a loss of $11.7 million ($0.12 loss per share) recorded in the six months ended June 30, 2007. A 174% increase in oil and natural gas production as well as a 148% improvement in the realized prices of crude oil were the contributing factors.

·	Revenues for the first six months of 2008 reached $54.0 million, a 553% increase from the same period last year.

·	Capital expenditures for the six months ended June 30, 2008, were $17.8 million, a 90% increase from the same period last year. All business units recorded higher levels of capital expenditures due to increased activity.

Subsequent Event – Business Combination

On July 29, 2008, we announced that we had entered into a definitive agreement providing for the business combination of Gran Tierra Energy and Solana Resources Limited (“Solana”). Under the terms of the Agreement, each Solana shareholder will receive either (i) 0.9527918 of a common share of Gran Tierra Energy or; (ii) 0.9527918 of a common share of a Canadian subsidiary of Gran Tierra Energy (an “Exchangeable Share”) for each common share of Solana held, which represents a premium of approximately 14.1 % to the 20 day weighted average trading price to July 28, 2008 of the Solana shares on the TSX Venture Exchange and Gran Tierra Energy’s July 28, 2008, closing price on the Toronto Stock Exchange of CAD $5.73. The shares of the Canadian subsidiary of Gran Tierra Energy: (i) will have the same voting rights, dividend entitlements and other attributes as Gran Tierra Energy common stock; (ii) will be exchangeable, at each shareholder’s option, on a one-for-one basis, into Gran Tierra Energy common stock; and (iii) subject to compliance with the listing requirements of the Toronto Stock Exchange, will be listed on the Toronto Stock Exchange. The Exchangeable Shares will automatically be exchanged for Gran Tierra Energy common stock five years from closing, and in certain other events.

New Reserves Report

As a result of the completion of an independent reserve audit by our reserve auditors relating to our development drilling program in the Costayaco field for the first half of 2008, we have increased our proved reserves in the Costayaco field to 6.67 million barrels of crude oil. This contrasts to our December 31, 2007 proved reserves of 3.27 million barrels of oil.

Restatement of Prior Year Financial Statements

Subsequent to the release of financial statements for the year ended December 31, 2007 we determined that $3.7 million of changes in our accounts payable and accrued liabilities, initially attributed to net cash provided by (used in) operating activities should have been attributed to oil and gas property expenditures and net cash used in investing activities (see notes 2 and 8 to our Condensed Unaudited Consolidated Financial Statements in Item 1). Accordingly, line items in the statements of cash flows for the six months ended June 30, 2007 have been restated.

Net changes in non-cash working capital related to accounts payable and accrued liabilities attributable to operating activities for the six months ended June 30, 2007 have been restated to a decrease of $1.4 million from an increase of $3.5 million, and net cash provided by (used in) operating activities had been restated to a use of $3.7 million from $1.3 million cash flow provided by operating activities. For the six months ended June 30, 2007, the change in non-cash working capital related to capital additions had been restated to a decrease of $1.6 million from a decrease of $6.6 million, cash used for oil and gas property expenditures (including the change in non-cash working capital related to capital additions) had been restated to $11.0 million from $16.0 million and net cash used in investing activities had been restated to $10.6 million from $15.5 million.

The preceding restatement had no effect on the net increase or decrease in cash or cash equivalents for any period.

Consolidated Results of Operations

	Three Months Ended June 30,						%			Six Months Ended June 30,						%
Consolidated Results of Operations	2008			2007			Change			2008			2007			Change
(Thousands of U.S. Dollars)
Revenue	$	33,042		$	3,611			815		$	53,791		$	7,935			578
Interest		102			139			(27	)		172			332			(48	)
		33,144			3,750			784			53,963			8,267			553

Operating Expenses		3,726			1,925			94			6,253			4,106			52
Depletion, Depreciation and Accretion		5,400			2,377			127			8,464			4,701			80
General and Administrative Expenses		4,641			2,680			73			8,774			4,619			90
Other Expenses		5,881			3,016			95			7,079			8,037			(12	)
		19,648			9,998			97			30,570			21,463			42

Income (Loss) before Income Taxes		13,496			(6,248	)		-			23,393			(13,196	)		-

Income Tax (Expenses) Recoveries		(4,970	)		1,176			-			(10,191	)		1,474			-

Net Income (Loss)	$	8,526		$	(5,072	)		-		$	13,202		$	(11,722	)		-

Production, Net of Royalties

Oil and NGL ("bbl") (1)		309,369			92,905			233			568,091			206,363			175
Natural Gas ("mcf")		-			1,060			(100	)		-			22,660			(100	)
Total Production ("boe") (1) (2)		309,369			92,958			233			568,091			207,496			174

Average Prices

Oil and NGL (per “bbl")	$	106.80		$	39.00			174		$	94.69		$	38.28			147
Natural Gas (per “mcf")		-		$	2.09			-			-		$	2.09			-

Consolidated Results of Operations (per “boe")

Revenue	$	106.80		$	38.85			175		$	94.69		$	38.24			148
Interest		0.33			1.50			(78	)		0.30			1.60			(81	)
		107.13			40.35			166			94.99			39.84			138

Operating Expenses		12.04			20.71			(42	)		11.01			19.79			(44	)
Depletion, Depreciation and Accretion		17.45			25.57			(32	)		14.90			22.66			(34	)
General and Administrative Expenses		15.00			28.83			(48	)		15.44			22.26			(31	)
Other Expenses		19.01			32.44			(41	)		12.46			38.74			(68	)
		63.50			107.55			(41	)		53.81			103.45			(48	)

Income (Loss) before Income Taxes		43.63			(67.20	)		-			41.18			(63.61	)		-

Income Tax (Expenses) Recoveries		(16.06	)		12.65			-			(17.94	)		7.11			-

Net Income (Loss)	$	27.57		$	(54.55	)		-		$	23.24		$	(56.50	)		-

(1) Gas volumes are converted to boe at the rate of 20 thousand cubic feet ("mcf") of gas per barrel of oil based upon the approximate relative values of natural gas and oil. Natural gas liquid (“NGL”) volumes are converted to boe on a one-to-one basis with oil.

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

Revenue for the three months ended June 30, 2008, was $33.0 million compared to $3.6 million recorded in the same period last year. Production of crude oil and NGL’s increased by 233% to 309,369 barrels, or 3,399 barrels per day. The increase in production coupled with a 174% increase in net realized crude oil prices to $106.80 per barrel resulted in the substantially higher revenue levels. A similar improvement in results was recorded for the six months ended June 30, 2008 with revenue increasing 578% to $53.8 million, production of crude oil increasing 175% to 568,091 barrels, or 3,121 per day, and average net realized prices for crude oil showing an improvement of 147% to $94.69 per barrel.

The majority of the increase in production and the net realized prices came from the Colombian operations. The increase in production is due primarily to the inclusion of production from two new discovery wells in the Costayaco and Juanambu fields in Colombia which commenced production in the third quarter of 2007. Natural gas production in 2008 is used for operating power generation with any excess production sold in the market.

Operating expenses for the current quarter amounted to $3.7 million, a 94% increase from the same quarter last year. The operating expenses for the first half of 2008 increased to $6.3 million from $4.1 million in the same period last year. The expanded operations and high production levels from the new fields in Colombia resulted in higher operating expenses. However, on a per boe basis, for the quarter ended June 30, 2008, the operating expenses declined by 42% to $12.04 compared to $20.71 recorded in the same quarter last year. A similar decline was also recorded for the first half of this year versus last year ($11.01 per boe compared to 19.79 per boe, a 44% decline). The new fields in Colombia with high production wells and low operating costs along with delays in planned workovers in both Colombia and Argentina have resulted in lower per boe operating costs in the respective periods.

Depletion, depreciation and accretion (“DD&A”) for the current quarter as well as the first half of this year increased to $5.4 million and $8.5 million, respectively, compared to $2.4 million and $4.7 million in the same periods last year, respectively. Increased production as well as higher depletable cost base accounted for the increases. On a boe basis, the DD&A in the second quarter was $17.45 per boe and $14.90 per boe for the six months ended June 30, 2008. These represent over 30% reductions from the same prior year periods due to the significant increase in proved reserves in Colombia.

General and administrative expenses (“G&A”) for the three and six months ended June 30, 2008, increased by 73% and 90% compared to the same periods last year. The increases were due to corporate stewardship costs including Sarbanes-Oxley compliance, securities exchange listing fees, securities registration related costs and increased stock-based compensation resulting from increased option grants. On a boe basis, the G&A stayed fairly consistent throughout the first six months of 2008 at about $15 per boe. This represents a significant decline from the G&A per boe recorded in the second quarter of last year of $28.83 and $22.26 in the first six months of 2007, 48% and 31% declines, respectively.

Other expenses comprise mainly a loss from derivative financial instruments recorded in 2008 and liquidated damages incurred in 2007. For the three and six months ended June 30, 2008, derivative losses were $6.3 million and $7.5 million, respectively, compared to $20,000 and $0.7 million for the three and six month ended June 30, 2007, respectively. Liquidated damages recorded in the three and six months ended June 30, 2007 were $3.2 million and $7.4 million, respectively, and no liquidation damages were recorded in 2008. Derivative losses relate to the costless collar hedging contract for crude oil based on West Texas Intermediate (“WTI”) price which we entered into in accordance with the terms of a credit facility. The liquidated damages relate to damages payable to our stockholders with respect to delays in certain share registration rights agreements becoming effective.

Income tax expense during the three months ended June 30, 2008 amounted to $5.0 million compared to a recovery of $1.2 million recorded in the same period last year. A tax expense of $10.2 million was recorded for the first half of 2008 compared to a recovery of $1.5 million recorded for the same period in 2007. The Colombian operations have generated net income before taxes of $22.6 million and $36.8 million for the three month and six months ended June 30, 2008, respectively, which resulted in local income tax expenses of $5.0 million and $10.4 million for the periods indicated. In Colombia, we have used Colombian income tax investment incentives, which permit additional tax deductions associated with capital investment in producing oil and natural gas properties, to decrease our current income tax otherwise payable.

Segmented Results of Operations

Our operations are carried out in Colombia and Argentina and we are headquartered in Calgary, Alberta, Canada. The Corporate Segment also includes the results of our start up activities in Peru. In 2008, Colombia has generated our net income and 93% of our revenues. The contribution from Colombia has been partially offset by derivative losses which are recorded as part of the Corporate Segment.

Segmented Results - Colombia

	Three Months Ended June 30,						%			Six Months Ended June 30,						%
Results of Operations	2008			2007			Change			2008			2007			Change
(Thousands of U.S. Dollars)
Revenue	$	30,793		$	1,965			1,467		$	50,158		$	4,153			1,108
Interest		79			43			84			141			137			3
		30,872			2,008			1,437			50,299			4,290			1,072

Operating Expenses		2,262			922			145			3,872			1,283			202
Depletion, Depreciation and Accretion		4,813			1,720			180			7,280			3,544			105
General and Administrative Expenses		1,498			323			364			2,520			732			244
Other Expenses		(276	)		(131	)		111			(215	)		(13	)		1,554
		8,297			2,834			193			13,457			5,546			143

Income (Loss) before Income Taxes	$	22,575			(826	)		(2,883	)	$	36,842			(1,256	)		(3,033	)

Production, Net of Royalties

Oil and NGL ("bbl") (1)(2)		258,633			45,348			470			474,000			94,556			401

Average Prices

Oil and NGL (per “bbl")	$	119.05		$	43.33			175		$	105.82		$	43.92			141

Segmented Results of Operations - Colombia (per “bbl”)

Revenue	$	119.05		$	43.33			175		$	105.82		$	43.92			141
Interest		0.31			0.95			(67	)		0.30			1.45			(79	)
		119.36			44.28			170			106.12			45.37			134

Operating Expenses		8.75			20.33			(57	)		8.17			13.57			(40	)
Depletion, Depreciation and Accretion		18.61			37.93			(51	)		15.36			37.48			(59	)
General and Administrative Expenses		5.79			7.12			(19	)		5.32			7.74			(31	)
Other Expenses		(1.07	)		(2.89	)		(63	)		(0.45	)		(0.14	)		221
		32.08			62.49			(49	)		28.40			58.65			(52	)

Income (Loss) before Income Taxes	$	87.28		$	(18.21	)		-		$	77.72		$	(13.28	)		-

(1)

NGL volumes are converted to boe on a one to one basis with oil.

(2)

Production represents production volumes adjusted for inventory changes.

Results of Operations - Colombia

For the three months ended June 30, 2008, income before income taxes from Colombia amounted to $22.6 million compared to a pre-tax loss of $0.8 million recorded in the same quarter last year. The results for the first six months of 2008 reflected a pre-tax income of $36.8 million compared to a pre-tax loss of $1.3 million recorded in the same period in 2007. In both comparative periods, the significant improvements in pre-tax income levels were due to increased production of crude oil and improved net realized prices partially offset by increased operating expenses, DD&A and G&A. On a per barrel basis, the pre-tax net income for the current quarter was $87.28 per barrel (six month pre-tax net income of $77.72 per barrel) versus a pre-tax loss of $18.21 recorded in the second quarter of 2007 (six month pre-tax loss of $13.28 per barrel).

Our Colombian operating results for 2008 are principally impacted by new oil production resulting from the success of our 2007 exploration program in Colombia, undertaken in the first half of 2007, where we made two field discoveries, Costayaco in the Chaza block and Juanambu in the Guayuyaco block. The exploration wells for these discoveries were brought into production in the third quarter of 2007 and have significantly increased our daily production.

During the quarter ended June 30, 2008, the production of crude oil and NGL’s increased by 470% to 2,842 barrels per day compared to 498 barrels per day produced in the second quarter of 2007. The production for the first six months amounted to 2,604 barrels per day compared to 522 barrels per day, an increase of 401% from the same period last year. These production levels are after government royalties ranging from 8% to 20% and third party royalties between 2% and 10%.

In Colombia, our revenue was also positively impacted by significantly improved net realized prices. The average net realized prices for crude oil, which are based on the global prices for WTI, increased by 175% to $119.05 per barrel in the three months ended June 30, 2008 compared to an average price of $43.33 realized in the same quarter last year. For the first six months of this year, the average realized price improved by 141% to $105.82 per barrel from $43.92 for the same period last year. The combination of these factors resulted in our revenue levels from Colombia in the second quarter and the six months ended June 30, 2008 increasing by almost 16 times to $30.8 million and 12 times to $50.2 million, respectively, from the comparable prior year periods.

For the three months ended June 30, 2008, the operating expenses in Colombia were $2.3 million compared to $0.9 million in the same quarter last year. For the six months ended June 30, 2008, operating expenses increased to $3.9 million compared to $1.3 million last year. The increased operating expenses resulted from the additional operations undertaken for the new discovery wells that came on production in the third quarter of 2007 and the increased cost associated with trucking oil from Costayaco to our pipeline. On a per boe basis, the operating expenses for the second quarter of 2008 were $8.75 per barrel compared to $20.33 per barrel incurred in the second quarter of last year ($8.17 per barrel for the first six months of 2008 versus $13.57 per barrel in the same period last year). Operating costs include trucking costs of $2.12 per barrel in the second quarter of 2008 (first six months - $1.54 per barrel) for Costayaco production. This cost is expected to decrease once construction of pipeline and related facilities for Costayaco are completed in the third quarter of 2008.

For both the three month and six month periods this year, the DD&A increased by 180% to $4.8 million and 105% to $7.3 million, respectively, compared to the same periods last year. Increased production levels coupled with higher depletable cost bases, partially offset by higher reserve levels, accounted for the increase in period over period DD&A levels. Although our Colombian proved reserves increased significantly in 2007 and 2008, we also invested much of our 2007 and 2008 year-to-date capital spending on the Colombian development program. On a per boe basis, the DD&A in Colombia for the current quarter was $18.61 per barrel compared to $37.93 per barrel recorded in the same quarter last year. For the six month periods in 2008 and 2007 DD&A per barrel recorded was $15.36 versus $37.48. Both comparative periods represent reductions in DD&A per barrel which reflect the increased reserve base partially offset by a higher depletable cost base. The first six months of 2007 did not benefit from the impact of the third quarter 2007 significant reserve additions which resulted from our two new discoveries.

Colombia’s G&A for the three months ended June 30, 2008 increased to $1.5 million from $0.3 million for the same period in 2007. For the six months ended June 30, 2008, the G&A rose to $2.5 million from $0.7 million incurred in the first six months of 2007. The increases in both comparative periods reflect higher management and administration expenses incurred to manage the increased level of development and operating activities resulting from the successful 2007 exploration and 2008 development activities. However, on a per boe basis, the G&A expenses declined by 19% to $5.79 per barrel for the current quarter compared to $7.12 incurred in the same quarter last year and by 31% to $5.32 from $7.74 for the six month periods.

Capital Program - Colombia

For the three months ended June 30, 2008, the capital expenditures in Colombia were $5.0 million and for the current six month period, the expenditures were $13.2 million. For the three months ended June 30, 2007, the capital expenditures in Colombia were $4.4 million and were $8.2 million for the six month period ended June 30, 2007. The increase in the capital expenditure program reflects expenditures associated with the development of the oil discoveries made in the third quarter of 2007.

In Colombia, capital expenditures for the three months ended June 30, 2008 included $3.4 million ($9.9 million for the six months ended June 30, 2008) of drilling, completion and testing costs for Costayaco -2, Costayaco -3 and Costayaco -4 and drilling costs for Costayaco – 5. Both Costayaco – 2 and Costayaco - 3 have been successfully tested for oil production with long term testing planned in the third quarter of 2008. Costayaco -4 and Costayaco -5 will commence short term production testing in the third quarter with long term testing planned for the fourth quarter of 2008. We commenced construction of a pipeline and related facilities to deliver crude oil from Costayaco to our Uchupayaco station and incurred $1.3 million in the three months ended June 30, 2008 ($1.7 million for the six months ended June 30, 2008). Other capital expenditures for the six months ended June 30, 2008 include $0.5 million of facility costs in Juanambu, leasehold improvements of $0.7 million for new office space in Bogota, seismic in various areas of $0.3 million and capitalized G&A of $0.2 million. In the second quarter of 2008, the exploration well, Popa -2, in the Rio Magdelena Block was successfully drilled (at no cost to Gran Tierra Energy) and is currently being evaluated. Palmera -1, a previously abandoned well in the Azar Block, was re-entered and tested in the second quarter (at no cost to Gran Tierra Energy). This well is being evaluated for production potential in the third and fourth quarter of 2008 and we will participate in a portion of the evaluation expenses.

In Colombia for the first six months ended June 30, 2007, we drilled the Juanambu-1 and Costayaco-1 wells for a net cost of $5.9 million. We drilled the Caneyes-1 well, which was dry and abandoned, at a cost to us of $1.7 million. We incurred costs of $0.6 million on other projects in Colombia during the first six months of 2007 for other exploration properties.

Outlook for Colombia

For the remainder of 2008, we intend to focus on developing our 2007 oil discoveries to increase our production capacity and reserve base, through development drilling and expansion of production and transportation infrastructure. In addition, we intend to undertake additional oil exploration efforts to further define the potential of our acreage in Colombia. Development drilling and exploration drilling program planned for the remainder of 2008 includes:

	-	Costayaco-2 and 3 long term testing in the third quarter of 2008;
	-	Costayaco-4 and Costayaco -5 testing for oil production in the third quarter of 2008;
	-	Costayaco – 6 and 7 to be drilled during the remainder of the year;
	-	Palmera -1 to be evaluated for production in the third and fourth quarters of 2008;
	-	Popa -2 to be tested for production in the third quarter of 2008;
	-	Juanambu - 2 planned for drilling in the third and fourth quarters of 2008; and
	-	One oil exploration well.

Segmented Results - Argentina

	Three Months Ended June 30,						%			Six Months Ended June 30,						%
Results of Operations		2008			2007			Change			2008			2007			Change
(Thousands of U.S. Dollars)
Revenue	$	2,249		$	1,646			37		$	3,633		$	3,782			(4	)
Interest		5			32			(84	)		10			32			(69	)
		2,254			1,678			34			3,643			3,814			(4	)

Operating Expenses		1,434			1,003			43			2,336			2,823			(17	)
Depletion, Depreciation and Accretion		556			630			(12	)		1,123			1,105			2
General and Administrative Expenses		386			386			-			955			708			35
Other Expenses		(156	)		(8	)		1,850			(132	)		54			-
		2,220			2,011			10			4,282			4,690			(9	)

Income (Loss) before Income Taxes	$	34		$	(333	)		(110	)	$	(639	)	$	(876	)		(27	)

Production, Net of Royalties

Oil and NGL ("bbl")		50,706			47,557			7			94,091			111,807			(16	)
Natural Gas ("mcf")		-			1,060			-			-			22,660			-
Total Production ("boe") (1) (2)		50,706			47,610			7			94,091			112,940			(17	)

Average Prices

Oil and NGL (per “bbl")	$	44.35		$	34.88			27		$	38.62		$	33.51			15
Natural Gas (per “mcf")		-		$	2.09			-			-		$	2.09			-

Consolidated Results of Operations (per “boe")

Revenue	$	44.35		$	34.58			28		$	38.62		$	33.49			15
Interest		0.10			0.67			(85	)		0.12			0.27			(56	)
		44.45			35.25			26			38.74			33.76			15

Operating Expenses		28.28			21.07			34			24.83			25.00			(1	)
Depletion, Depreciation and Accretion		10.97			13.23			(17	)		11.94			9.78			22
General and Administrative Expenses		7.61			8.11			(6	)		10.16			6.27			62
Other Expenses		(3.08	)		(0.17	)		1,712			(1.39	)		0.49			-
		43.78			42.24			4			45.54			41.54			10

Income (Loss) before Income Taxes	$	0.67		$	(6.99	)		-		$	(6.80	)	$	(7.78	)		-

(1) Gas volumes are converted to boe at the rate of 20 mcf of gas per barrel of oil based upon the approximate relative values of natural gas and oil. NGL volumes are converted to boe on a one-to-one basis with oil.

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

Results of Operations - Argentina

For the three months ended June 30, 2008, income before income taxes from Argentina operations was $34,000 compared to a pre-tax loss of $0.3 million recorded in the same quarter last year. The operating results for the quarter were positively affected by a 7% increase in production of crude oil and NGL’s and a 27% increase in net realized prices. These factors were partially offset by a 10% increase in overall expenses. On a per boe basis, the pre-tax net income was $0.67 per boe compared to a pre-tax loss of $6.99 reported in the same quarter last year.

For the first six months of this year, the results reflected a pre-tax loss of $0.6 million compared to a pre-tax loss of $0.9 million recorded in the first six months of the prior year. A 16% decline in production of crude oil and NGL’s was essentially offset by a 15 % increase in net realized prices. The positive variance from last year resulted mainly from a 9% decline in overall expenses. On a per boe basis, the pre-tax loss was $6.80 per boe compared to a pre-tax loss of $7.78 reported in the same quarter last year.

For the three months ended June 30, 2008, in Argentina, crude oil and NGL’s production, after 12% royalties, increased by 7% to 557 barrel per day compared to 523 barrels per day in the same quarter last year. However, for the six months ended June 30, 2008, the daily production levels declined by 16% to 517 barrels per day compared to 618 barrel per day produced in the same period in 2007. The production levels in the first quarter of 2008 were negatively affected by poor road conditions which delayed deliveries to Refineria del Norte S.A. returning to normal levels in the second quarter of 2008. Natural gas production in 2008 is used for operating power generation with any excess production sold in the market.

The average price received for crude oil in Argentina is controlled and currently the price we receive is $38 per barrel. Currently all oil and gas producers in Argentina are operating without sales contracts. A new withholding tax regime was introduced in Argentina without specific guidance as to its application. Producers and refiners of oil in Argentina have been unable to determine an agreed sales price for oil deliveries to refineries. We were receiving $33 per barrel, which is a price offered by Refiner S.A., the purchaser of our crude oil, based on their netback, for production from November 18, 2007, the effective date of the decree to March 31, 2008. In April 2008, we completed negotiations with Refiner S.A to increase the price received for all deliveries from November 18, 2007 to March 31, 2008 to $38 per barrel. The additional $5 per barrel was recorded as revenue in the second quarter of 2008. Along with most other oil producers in Argentina, we are continuing deliveries to the refinery and are negotiating a price for deliveries commencing April 1, 2008. The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced by the lower sales price. We are working with other oil and gas producers in the area, as well as Refiner S.A. and provincial governments, to lobby the federal government for change.

The average realized price for crude oil and NGL’s in Argentina was $44.35 per barrel in the second quarter of 2008 and $38.62 per barrel for the six months ended June 30, 2008 reflecting the additional $5 per barrel as discussed above. These 2008 realized prices compare to $34.88 and $33.51 for the three and six months ended June 30, 2007, respectively. The average realized prices are after deducting royalties at an average rate of 12% of production revenue, and after deducting turnover taxes. The slower growth in the average prices in Argentina versus the price growth for WTI was caused mainly by the application of a new Argentine withholding tax on oil exports implemented in the fourth quarter of 2007, as discussed above.

In Argentina, revenues for the three months ended June 30, 2008, after deducting royalties at an average rate of 12% of production revenue, and after deducting turnover taxes, increased 37% to $2.2 million for crude oil and natural gas as compared to $1.6 million for the same quarter of 2007, reflecting the impact of higher production and average prices offset partially by higher export taxes, as explained above. For the six months ended June 30, 2008, revenue levels declined by 4% compared to the first six months of prior year, due to a 17% decline in production partially offset by a 15% increase in average prices. The increase in average prices was hampered by the introduction of withholding taxes as explained above.

Operating expenses for the second quarter of 2008, increased to $1.4 million ($28.28 per boe) compared to $1.0 million ($21.07 per boe) incurred in the same quarter last year. The increase was mainly attributable to the commencement of first quarter 2008 rain delayed workovers and other second quarter 2008 scheduled workovers in the second quarter of 2008. However, for the current six month period, operating expenses declined to $2.3 million from $2.8 million incurred in the same period a year ago mainly due to workover expenses undertaken in 2007. The decrease in workover expenses in 2008 was caused by adverse weather conditions in the first quarter of 2008. For the comparative six month periods, operating expenses on a per boe basis stayed consistent at approximately $25 per boe.

DD&A for the three months ended June 30, 2008 was $0.6 million, slightly below the amount recorded in the second quarter of 2007. On a per boe basis, the decline was greater at $10.97 per boe versus $13.23 per boe. The impact of higher production levels and lower proved reserves was more than offset by a decreasing proved depletable cost base. This decreasing proved depletable cost base is a result of reduced development expenditures in Argentina. For the first six months of 2008, the DD&A was essentially unchanged from last year at $1.1 million.

The G&A for the three months ended June 30, 2008 remained unchanged from the same quarter last year at $0.4 million but due to higher production levels, on a per boe basis, it declined to $7.61 per boe from $8.11 incurred in the same period in 2007. On a six month basis, the G&A increased by 35% to $1.0 million from $0.7 million in the same period of 2007 as a result of increased stock-based compensation expense for Argentine staff and increased consulting expenses associated with the operations. On a per boe basis, for the six month comparative periods, the G&A rate increased by 62% to $10.16 due to higher expense levels as well as the impact of lower production in the first quarter of 2008.

Capital Program - Argentina

Our capital expenditures in the second quarter of 2008 in Argentina were $2.1 million bringing the total expenditures in the region for the first six months of 2008 to $2.5 million. This represents a significant increase from the capital program of $0.6 million spent in the first six months of 2007. The expenditures incurred in Argentina during the current six month period comprised of $1.6 million of drilling expense for the exploration well, Proa -1, in the Surubi block. Other capital expenditures for the six months ended June 30, 2008, were facilities upgrade costs of $0.3 in Palmar Largo area, exploration land lease costs and capitalized G&A including non-cash stock-based compensation expense.

In Argentina, capital expenditures for the six months ended June 30, 2007, were $0.6 million. We incurred costs of $0.6 million to complete the Puesto Climaco-2 sidetrack well in the Vinalar Block which was drilled in December 2006.

Outlook for Argentina

In 2008, we intend to undertake additional oil exploration efforts to further define the potential of our acreage in Argentina. This includes the completion and testing of the drilling of the Proa -1 exploration well and complete several well workovers on existing producing and shut-in fields.

Segmented Results – Corporate

	Three Months Ended June 30,						%			Six Months Ended June 30,						%
Results of Operations	2008			2007			Change			2008			2007			Change
(Thousands of U.S. Dollars)
Interest	$	18		$	64			(72	)	$	21		$	163			(87	)

Operating Expenses		30			-						45			-
Depletion, Depreciation and Accretion		31			27			15			61			52			17
General and Administrative Expenses		2,758			1,970			40			5,300			3,179			67
Liquidated Damages		-			3,235			(100	)		-			7,367			(100	)
Loss from Derivative Financial Instruments		6,278			20			31,290			7,462			677			1,002
Foreign Exchange Loss (Gain)		34			(99	)		(134	)		(37	)		(48	)		(23	)
		9,131			5,153			77			12,831			11,227			14

Loss before Income Taxes	$	(9,113	)	$	(5,089	)		79		$	(12,810	)	$	(11,064	)		16

Results of Operations - Corporate

The Corporate Segment also includes the results of our start up operations in Peru.

The corporate G&A for the three months ended June 30, 2008, were $2.8 million reflecting a 40% increase from the same quarter a year ago. For the current six month period the increase was 67% to $5.3 million from the same six month period last year. The increase in G&A was due to corporate stewardship costs including Sarbanes-Oxley compliance, securities exchange listing fees in both Canada and the United States, securities registration related costs and increased stock-based compensation due to increased option grants.

Liquidated damages expensed in 2007 were $3.2 million in the second quarter and $7.4 million in the first six months of 2007 and related to liquidated damages payable to our stockholders as a result of the registration statement for 50 million units sold in the second quarter of 2006 not becoming effective within the period specified in the share registration rights agreements for those securities. This registration statement became effective on May 14, 2007 and no additional liquidated damages were incurred after that time.

In accordance with the terms of the credit facility with Standard Bank Plc, we entered into a costless collar hedging contract for crude oil based on WTI price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. For the three months ended June 30, 2008, we recorded a loss of $6.3 million on the valuation of these derivative financial instruments. For the comparative period last year the loss was not significant. The valuation loss for the first six months of 2008 was $7.5 million compared to $0.7 million reported in the same period last year.

Capital Program - Corporate

The capital expenditures for the Corporate Segment during the three months ended June 30, 2008 were $1.5 million bringing the total expenditures in 2008 year-to-date to $2.1 million. The 2008 capital expenditures for the Corporate Segment included continuation of an aero magnetic and gravity survey over our two exploration blocks in Peru. This program commenced in the fourth quarter of 2007 and was completed in the second quarter of 2008. Expenditures in the second quarter of 2008 were $1.4 million and $1.9 million for the six months ended June 30, 2008.

Outlook for Corporate

In Peru, we are currently applying to the Peruvian Government to have Environmental Impact Assessments (“EIAs”) to be carried out on each of the two exploration blocks. Upon successful completion of the EIA assessments, we intend to apply for permits to carry out seismic on each of the blocks.

Liquidity and Capital Resources

Net cash provided by operating activities for the six months ended June 30, 2008 increased to $12.4 million compared to cash used in operating activities of $3.7 million for the same period in 2007. The increase was mainly due to the significant increase in oil sales offset by increased operating and G&A expenses as well as higher operating working capital requirements.

Net cash used in investing activities for the six months ended June 30, 2008 amounted to $11.8 million compared to $10.6 million in the same period in 2007. A higher level of capital expenditures was partially offset by the increase in non-cash working capital related to the capital program. The capital expenditures of $17.8 million in the first six months of 2008 comprised $13.2 million in Colombia, $2.5 million in Argentina, $2.1 for corporate activities, non-cash stock-based compensation expense of $0.3 million and are offset by a change in non-cash working capital related to investing activities of $5.8 million. The comparative amounts for the same period last year were $8.2 million in Colombia, $0.6 million in Argentina and $0.5 million for corporate activities for a total expenditure of $9.4 million adjusted to include the change in non-cash working capital related to investing activities of $1.6 million.

Net cash provided by financing activities for the six months ended June 30, 2008 was $16.5 million ($nil for the six months ended June 30, 2007) as a result of the issuance of common shares upon exercise of warrants and stock options.

Overall during the six months ended June 30, 2008, we increased our cash balances by $17.1 million as compared to a decrease in the six months ended June 30, 2007 of $14.3 million. As of June 30, 2008, our cash balance was $35.3 million and our current assets (including cash and cash equivalents) less current liabilities was $31.7 million, compared to cash of $18.2 million and current assets less current liabilities of $8.1 million at December 31, 2007. During the six months ended June 30, 2007 we reduced our cash balances by $14.3 million. We had cash outflows of $3.7 million from operating activities and $10.6 million outflows from investing activities including oil and gas property expenditures of $8.2 million relating primarily to our drilling and other oilfield activities primarily in Colombia.

In addition to our cash balances and our positive working capital position, effective February 28, 2007, we entered into a credit facility with Standard Bank Plc. The facility has a three-year term which may be extended by agreement between the parties. The borrowing base is the present value of our petroleum reserves up to maximum of $50 million. The initial borrowing base is $7 million and the borrowing base will be re-determined semi-annually based on reserve evaluation reports. As a result of Standard Bank Plc’s review of our Mid-Year 2007 Independent Reserve Audit, we have received preliminary approval to increase our borrowing base to $20 million; however, we have not pursued this further as the additional credit is not required at this time. The facility includes a letter of credit sub-limit of up to $5 million. Amounts drawn down under the facility bear interest at the Eurodollar rate plus 4%. A stand-by fee of 1% per annum is charged on the un-drawn amount of the borrowing base. The facility is secured primarily by our Colombian assets. Under the terms of the facility, we are required to maintain compliance with specified financial and operating covenants. We were required to enter into a derivative instrument for the purpose of obtaining protection against fluctuations in the price of oil in respect of at least 50% of the June 30, 2006 Independent Reserve Evaluation Report projected aggregate net share of Colombian production after royalties for the three-year term of the Facility. As of December 31, 2007 and June 30, 2008, no amounts have been drawn-down under the facility.

Based on projected production, prices, costs and our current liquidity position, we believe that our current operations and capital expenditure program can be maintained from cash flow from existing operations, cash on hand, and our credit facility, 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, or issuance of equity.

Future growth and acquisitions will depend on our ability to raise additional funds through equity and debt markets. Increases in the borrowing base under our credit facility are dependent on our success in increasing oil and gas reserves and on future oil prices. Additional funds will be provided to us if holders of our warrants to purchase common shares decide to exercise the warrants.

Our initiatives to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities may be affected by the market value of our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing stockholders, and this dilution would be exacerbated by a decline in stock price. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets that are not currently pledged under our existing credit facility.

Contractual Obligations

Our future lease payments and other contractual obligations at June 30, 2008 were not substantially different than at December 31, 2007.

Critical Accounting Estimates

The preparation of financial statements under generally accepted accounting principles (“GAAP”) in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. On a regular basis we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting estimates with the Audit Committee of the Board of Directors.

We believe that the assumptions, judgments and estimates involved in the accounting for oil and gas accounting and impairment, reserves determination, asset retirement obligation, share-based payment arrangements, goodwill impairment, warrants and income taxes have the greatest potential impact on our condensed consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting estimates. Historically, our assumptions, judgments and estimates relative to our critical accounting estimates have not differed materially from actual results.

Our critical accounting estimates are disclosed in Item 7 of our 2007 Annual Report on Form 10-K/A, filed with the Securities and Exchange Commission on May 12, 2008, and have not changed materially since the filing of that document.

ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our principal market risk relates to oil prices. We have not hedged these risks in the past, except as required by our credit facility, as described below. Essentially 100% of our revenues are from oil sales at prices which are defined by contract relative to WTI and adjusted for transportation and quality, for each month. In Argentina, a further discount factor which is related to a tax on oil exports establishes a common pricing mechanism for all oil produced in the country, regardless of its destination.

In accordance with the terms of the credit facility with Standard Bank Plc, which we entered into on February 28, 2007, we entered into a costless collar hedging contract for crude oil based on the WTI price, with a floor of $48.00 and a ceiling of $80.00, for a three-year period ending February 2010, for 400 barrels per day from March 2007 to December 2007, 300 barrels per day from January 2008 to December 2008, and 200 barrels per day from January 2009 to February 2010. At June 30, 2008, the value of this costless collar was a loss of $8.4 million. A hypothetical 10% increase in WTI price on June 30,2008 would cause the loss to increase by approximately $1.9 million for the quarter, and a hypothetical 10% decrease in WTI price on June 30, 2008 would cause the loss to decrease by approximately $1.8 million for the quarter. This compares to at December 31, 2007, when the value of this costless collar was a loss of $2.6 million, and a hypothetical 10% increase in WTI price on December 31, 2007 would cause the loss to increase by approximately $1.5 million, and a hypothetical 10% decrease in WTI price on December 31, 2007 would cause the loss to decrease by approximately $1.3 million.

We consider our exposure to interest rate risk to be immaterial. Interest rate exposures relate entirely to our investment portfolio, as we do not have short-term or long-term debt. However, if we draw down amounts under our credit facility with Standard Bank Plc, we will incur interest rate risk with respect to the amounts drawn down and outstanding. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates. 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 crude oil. In Colombia, we receive 75% of oil revenues in U.S. dollars and 25% in Colombian pesos at current exchange rates. The majority of our capital expenditures in Colombia are in U.S. dollars and the majority of local office costs are in local currency. As a result, the 75%/25% allocation between U.S. dollar and peso denominated revenues is approximately balanced between U.S. and peso expenditures, providing a natural currency hedge. In Argentina, reference prices for oil are in U.S. dollars and revenues are received in Argentine pesos according to current exchange rates. The majority of capital expenditures within Argentina have been in U.S. dollars with local office costs generally in pesos. While we operate in South America exclusively, the majority of our spending since our inauguration has been for acquisitions. The majority of these acquisition expenditures have been valued and paid in U.S. dollars.

ITEM 4. - CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act) that are designed to provide reasonable assurance that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the required time periods.

Our management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l5d-15 of the Exchange Act. Based on their evaluation, our principal executive and principal financial officers have concluded that Gran Tierra Energy's disclosure controls and procedures were not effective as of June 30, 2008 to ensure that the information required to be disclosed by Gran Tierra Energy in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission ("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. Our Chief Executive Officer and Chief Financial Officer arrived at this assessment based on the determination that we had a material weakness in our internal control over financial reporting, as discussed below, which management has not been able to fully test to determine that it has been remediated.

Remediation of Material Weakness

We are taking steps to remediate the material weakness disclosed in Gran Tierra Energy's Form 10-K/A for the year ended December 31, 2007, filed with the Securities and Exchange Commission on May 12, 2008. The material weakness relates to a misclassification of cash flows from operating activities, with a corresponding offset to cash flows from investing activities, in the statement of cash flows. The control over the entry of data into a spreadsheet used in the preparation of the statement of cash flows and the monitoring thereof was not sufficiently precise to prevent the misclassification from occurring. Because this material weakness was not remediated prior to June 30, 2008, our management, including our principal executive and principal financial officers, concluded that this material weakness continued to exist at the end of the period covered by this report. The misclassifications had no effect on our previously reported net change in cash and cash equivalents and no impact on our previously reported consolidated balance sheets or consolidated statements of operations and accumulated deficit for the periods affected by the misclassification. Management intends to review and verify the data entered into a spreadsheet used to calculate the changes in accounts payable and accrued liability balances, used to determine cash flows from operating and investing activities. Management's intent is to test this control during the third and fourth quarters of 2008.

Changes in Internal Control over Financial Reporting

In the second quarter of 2008, the Company made changes to the design and operating effectiveness of the internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) related to the remediation of the material weakness disclosed in Gran Tierra Energy’s Form 10-K/A for the year ended December 31, 2007, filed with the Securities and Exchange Commission on May 12, 2008.

These changes have materially affected or are likely to materially affect our internal control over financial reporting. Management has implemented internal control design and operating effectiveness changes by: creating new worksheets requiring detailed reconciliations of all statement of cash flow line items and business segment changes in accounts payable and accrued liability balances used to determine cash flows from operating and investing activities; implementing review procedures to ensure proper segregation of duties through identification of roles and responsibilities; and, adding an additional qualified staff accountant to enhance segregation of duties in the preparation, review and approval of the Statement of Cash Flows.

ITEM 4T – CONTROLS AND PROCEDURES

Not applicable.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Ecopetrol and Gran Tierra Colombia, the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the procedure for allocation of oil produced and sold during the long term test of the Guayuyaco-1 and Guayuyaco-2 wells. There is a material difference in the interpretation of the procedure established in the Clause 3.5 of Attachment-B of the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for benefit of Ecopetrol. There has been no agreement between the parties, and Ecopetrol has filed a lawsuit in the Contravention Administrative Court in the District of Cauca regarding this matter. Gran Tierra Energy filed a response on April 29, 2008 in which we refuted all of Ecopetrol’s claims and requested a change of venue to the courts in Bogota. The administrative justices of Bogota have been commissiones to administer the gathering of evidence by the Administrative Tribune of Cauca. At this time no amount has been accrued in the financial statements as we do not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $5.8 million, which possible loss is shared 50% with our partner Solana Petroleum Exploration (Colombia) S.A., with the remaining 50% the responsibility of Gran Tierra Colombia.

This matter was reported in our Annual Report on Form 10-K/A for the year ended December 31, 2007, filed with the Securities and Exchange Commission on May 12, 2008.

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2007. The risks relating to our business and industry, as set forth in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2007, filed with the Securities and Exchange Commission on May 12, 2008, are set forth below, and the risks that we have updated are designated by an asterisk (*).

Risks Related to Our Business

* We are a Company With Limited Operating History for You to Evaluate Our Business.

As an oil and gas exploration and development company, which commenced operations in 2005, we have a limited operating history, and therefore it is difficult for potential investors to evaluate our business. Our operations are subject to all of the risks frequently encountered in the development of any new business, including control of expenses and other difficulties, complications and delays, as well as those risks that are specific to the oil and gas industry. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets and operations in new countries. We may never overcome these obstacles. Our accumulated deficit as of June 30, 2008 is $3.3 million.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and gas reserves on terms that will be commercially viable for us. If we are unable to do so, or unable to do so at the level we intend, then we may never attain profitability.

Unanticipated Problems in Our Operations May Harm Our Business and Our Viability.

If our operations in South America are disrupted and/or the economic integrity of these projects is threatened for unexpected reasons, our business may experience a setback. These unexpected events may be due to technical difficulties, operational difficulties which impact the production, transport or sale of our products, geographic and weather conditions, business reasons or otherwise. Because we are at the early stages of our development, we are particularly vulnerable to these events. Prolonged problems may threaten the commercial viability of our operations. Moreover, the occurrence of significant unforeseen conditions or events in connection with our acquisition of operations in South America may cause us to question the thoroughness of our due diligence and planning process which occurred before the acquisitions, and may cause us to reevaluate our business model and the viability of our contemplated business. Such actions and analysis may cause us to delay development efforts and to miss out on opportunities to expand our operations.

We May Be Unable to Obtain Development Rights We Need to Build Our Business, and Our Financial Condition and Results of Operations May Deteriorate.

Our business plan focuses on international exploration and production opportunities, initially in South America and later in other parts of the world. Thus far, we have acquired interests for exploration and development in eight properties in Argentina, nine properties in Colombia and two properties in Peru. 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.

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

Our business will focus on the oil and gas industry in a limited number of properties, initially in Argentina, Colombia and Peru, with the intention of expanding elsewhere into other countries. Larger companies have the ability to manage their risk by diversification. However, we will lack diversification, in terms of both the nature and geographic scope of our business. As a result, factors affecting our industry or the regions in which we operate will likely impact us more acutely than if our business were more diversified.

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

Our ability to successfully bid on and acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements will depend on developing and maintaining effective working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair Gran Tierra Energy’s ability to grow.

To develop our business, we will endeavor to use the business relationships of our management and board of directors to enter into strategic relationships, which may take the form of joint ventures with other private parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

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. This competition is increasingly intense as prices of oil and natural gas on the commodities markets have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger, foreign owned companies, which, in particular, may have access to greater resources than us, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.

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

We expect that our cash balances and cash flow from operations and existing credit facility will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties in Argentina and Colombia will be sufficient only to fund our currently planned operations. We will require additional capital to continue to operate our business beyond our current planned activities and to expand our exploration and development programs to additional properties. We may be unable to obtain additional capital required. Furthermore, inability to obtain capital may damage our reputation and credibility with industry participants in the event we cannot close previously announced transactions.

When we require such additional capital we plan to pursue sources of such 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 are likely to be dilutive to our stockholders, as we will most likely issue additional shares of common stock or other equity to investors in future financing transactions. In addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which will adversely impact our financial condition.

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

If We Fail to Make the Cash Calls Required by Our Current Joint Ventures or Any Future Joint Ventures, We May be Required to Forfeit Our Interests in These Joint Ventures and Our Results of Operations and Our Liquidity Would be Negatively Affected.

If we fail to make the cash calls required by our joint ventures, we may be required to forfeit our interests in these joint ventures, which could substantially affect the implementation of our business strategy. In the future we will be required to make periodic cash calls in connection with our operated and non-operated joint ventures, or we may be required to place funds in escrow to secure our obligations related to our joint venture activity. If we fail to make the cash calls required in connection with the joint ventures, whether because of our cash constraints or otherwise, we will be subject to certain penalties and eventually would be required to forfeit our interest in the joint venture.

*We have entered into a definitive agreement with Solana Resources Limited providing for the business combination of our company with Solana, which exposes us to financial and other risks.

On July 28, 2008, we entered into a definitive agreement providing for the business combination of our company with Solana Resources Limited. Under the terms of the Agreement, at the closing of the transaction each Solana shareholder will receive shares of our common stock, or shares exchangeable for shares of our common stock, which would result in, on a diluted basis, Solana securityholders owning approximately 49% of the combined company and Gran Tierra Energy securityholders owning approximately 51% of the combined company. The proposed transaction is subject to regulatory, stock exchange, court and shareholder approvals. If the transaction does not close because of a failure on our part to perform, we may be required to pay Solana a termination fee of $21 million in certain circumstances and an expense reimbursement fee of $1.5 million in certain other circumstances. In addition, if the transaction does not close then we will have incurred significant expenses in negotiating and attempting to close the transaction, which we may not be able to recoup.

If the proposed transaction does close we are subject to a number of risks, including:

·	we may find that we have difficulty integrating the operations or personnel of our company and Solana, or retaining the key personnel of the acquired company;

·	our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues;

·	we may find that we are not able to realize the benefits from the combination of the two companies due to unanticipated reasons;

·	we may find that we are subject to liabilities of Solana of which we were not aware, despite our due diligence efforts; and

·	our market price may decline if a substantial number of shares are sold following the transaction by Solana stockholders.

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

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We may not be able to:

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

allocate our human resources optimally;

identify and hire qualified employees or retain valued employees; or

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

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

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

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting the business of Gran Tierra Energy. We have a small management team consisting of Dana Coffield, our President and Chief Executive Officer, Martin Eden, our Vice President, Finance and Chief Financial Officer, Max Wei, our Vice President, Operations, Rafael Orunesu, our President of Gran Tierra Argentina SA, and Edgar Dyes, our President of Gran Tierra Colombia Ltd. (“Gran Tierra Colombia”). The loss of any of these individuals or our inability to attract suitably qualified staff could materially adversely impact our business. We may also experience difficulties in certain jurisdictions in our efforts to obtain suitably qualified staff and retaining staff who are willing to work in that jurisdiction. We do not currently carry life insurance for our key employees.

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

Risks Related to our Prior Business May Adversely Affect our Business.

Before the share exchange transaction between Goldstrike and Gran Tierra Canada, Goldstrike’s business involved mineral exploration, with a view towards development and production of mineral assets, including ownership of 32 mineral claim units in a property in British Columbia, Canada and the exploration of this property. We have determined not to pursue this line of business following the share exchange, but could still be subject to claims arising from the former Goldstrike business. These claims may arise from Goldstrike’s operating activities (such as employee and labor matters), financing and credit arrangements or other commercial transactions. While no claims are pending and we have no actual knowledge of any threatened claims, it is possible that third parties may seek to make claims against us based on Goldstrike’s former business operations. Even if such asserted claims were without merit and we were ultimately found to have no liability for such claims, the defense costs and the distraction of management’s attention may harm the growth and profitability of our business. While the relevant definitive agreements executed in connection with the share exchange provide indemnities to us for liabilities arising from the prior business activities of Goldstrike, these indemnities may not be sufficient to fully protect us from all costs and expenses.

Maintaining and improving our financial controls may strain our resources and divert management's attention, and if we are not able to report that we have effective internal controls our stock price may suffer.

We are subject to the requirements of the Securities Exchange Act of 1934, or the Exchange Act, including the requirements of the Sarbanes-Oxley Act of 2002. The requirements of these rules and regulations have increased, and we expect will continue to increase, our legal and financial compliance costs, make some activities more difficult, time consuming or costly and may also place undue strain on our personnel, systems and resources. The Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting. This can be difficult to do. As a result of this and similar activities, management's attention may be diverted from other business concerns, which could have a material adverse effect on our business, financial condition and results of operations.

We Have a Material Weakness In Our Internal Control Over Financial Reporting, and This Material Weakness Creates a Reasonable Possibility That a Material Misstatement of Our Interim or Annual Financial Statements Will Not Be Prevented or Detected in a Timely Manner.

As a publicly-traded company, we must maintain disclosure controls and procedures and internal control over financial reporting. Our management determined that we have a material weakness in our internal control over financial reporting as of December 31, 2007, relating to the accounting for changes in our accounts payable and accrued liability balances in our statements of cash flow. As a result of this material weaknesses in internal control over financial reporting, material misstatements existed in our statements of cash flow for the years ended December 31, 2007 and 2006, and in our interim financial statements in 2007. To improve and to maintain the effectiveness of our internal control over financial reporting and disclosure controls and procedures, significant resources and management oversight may be required. As a result of this and similar activities, management's attention may be diverted from other business concerns, which could have a material adverse effect on our business, financial condition and results of operations. If we are unable to remediate the material weakness, or in the future report one or more additional material weaknesses, there is a possibility that this could result in a restatement of our financial statements or impact our ability to accurately report financial information on a timely basis, which could adversely affect our stock price. Further, the presence of one or more material weaknesses could cause us to not be able to timely file our periodic reports with the Securities and Exchange Commission, which could also result in law suits or diversion of management's attention to our business.

We Must Maintain Effective Registration Statements For All of Our Private Placements of Our Common Stock, and the Restatement of Our Financial Statements Will Require Us to Amend These Registration Statements.

We are required to file Post Effective Amendments to our registration statements periodically in accordance with the Registration Rights Agreements for our 2005 and 2006 private placements of units. As a result of our restatement of our financial statements, we will be required to amend all three registration statements. Amending and keeping these registration statements effective is costly and diverts management’s attention from running our business.

Risks Related to Our Industry

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.

We May Not Be Able to Develop Oil and Gas Reserves on an Economically Viable Basis, and Our Reserves and Production May Decline as a Result.

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

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

Unless We are Able to Replace Reserves Which We Have Produced, Our Cash Flows and Production will Decrease Over Time.

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.

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

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

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

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

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

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. 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. We will obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

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 do not require a significant reserve account for these potential costs in respect of any of our current properties or facilities at this time but 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 such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Our Inability to Obtain Necessary Facilities 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 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 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.

We are not the Operator of All Our Current Joint Ventures and Therefore the Success of the Projects Held Under Joint Ventures is Substantially Dependent On Our Joint Venture Partners.

As our company does not operate all the joint ventures we are currently involved in, we do not have a direct control over non-operated joint ventures. When we participate in decisions as a joint venture partner, we must rely on the operator’s disclosure for all decisions. Furthermore, the operator is responsible for the day to day operations of the joint venture including technical operations, safety, environmental compliance, relationships with governments and vendors. As we do not have full control over the activities of our non-operated joint ventures, our results of operations for those ventures are dependent upon the efforts of the operating partner.

We May Have Difficulty Distributing Our Production, Which Could Harm Our Financial Condition.

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

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

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

The entire Argentine domestic refining market is small and export opportunities are limited by available infrastructure. As a result, our oil sales in Argentina will depend on a relatively small group of customers, and currently, on just one customer in the area of our activity in the country. During 2007, we sold all of our production in Argentina to Refiner S.A. The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results . Currently all operators in Argentina are operating without sales contracts. We cannot provide any certainty as to when the situation will be resolved or what the final outcome will be.

Oil sales in Colombia are made to Ecopetrol, a government agency. While oil prices in Colombia are related to international market prices, lack of competition for sales of oil may diminish prices and depress our financial results.

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

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

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

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. Oil from our new discoveries at Costayaco-1 and Juanumbu-1 is trucked a short distance to the entry point of our pipeline, and adverse weather conditions and security issues can cause delays in trucking. Once delivered to Ecopetrol, all of our current oil production in Colombia is transported by an export pipeline which provides the only access to markets for our oil. Without other transportation alternatives, sales of oil could be disrupted by landslides or other natural events which impact this pipeline.

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

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for WTI in 2000 was $30 per barrel. In 2006, it was $66 per barrel and in 2007 it was $72 per barrel. 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. Although during 2007 market prices for oil and natural gas have remained at high levels, these prices may not remain at current levels. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differences. These differentials can change over time and have a detrimental impact on realized prices. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

In addition, oil and natural gas prices in Argentina are effectively regulated and as a result are 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, a government agency and the purchaser of all oil that we produce in Colombia, may cause realized prices to be lower than those received in North America.

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

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

Negative Economic, Political and Regulatory Developments in Argentina, Including Export Controls May Negatively Affect our Operations.

The Argentine economy has experienced volatility in recent decades. This volatility has included periods of low or negative growth and variable levels of inflation. Inflation was at its peak in the 1980’s and early 1990’s. In late-2001 there was a deep fiscal crisis in Argentina involving restrictions on banking transactions, imposition of exchange controls, suspension of payment of Argentina’s public debt and abrogation of the one-to one peg of the peso to the dollar. For the next year, Argentina experienced contractions in economic growth, increasing inflation and a volatile exchange rate. Currently, GDP is growing, inflation is normalized, and public finances are strengthened. However, there is no guarantee of economic stability. Any de-stabilization may seriously impact the economic viability of operations in the country or restrict the movement of cash into and out of the country, which would impair current activity and constrain growth in the country.

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

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

Our agreements with Refiner S.A. expired on January 1, 2008, and renegotiation, though currently underway, has been delayed due to the introduction of a new withholding tax regime for crude oil and refined oil products exported and sold domestically in Argentina. Currently all oil and gas producers in Argentina are operating without sales contracts. The new withholding tax regime was introduced without specific guidance as to its application. Producers and refiners of oil in Argentina have been unable to determine an agreed sales price for oil deliveries to refineries. Also, the price for refiners’ gasoline production has been capped below the price that would be received for crude oil. Therefore, the refineries’ price offered to oil producers reflects their price received, less taxes and operating costs and their usual mark up. In our case we are receiving $38 per barrel for production since November 18, 2007, the effective date of the decree. Along with most other oil producers in Argentina, we are continuing deliveries to the refinery and will continue to receive $38 per barrel until the situation around the decree is rectified by the government. The Provincial Governments have also been hurt by these changes as their effective royalty take has been reduced by the lower sales price. We are working with other oil and gas producers in the area, as well as Refiner S.A., and provincial governments, to lobby the federal government for change .There has been a delay in rectifying the situation in Argentina because of a change in government in December 2007, and the months of January and February are generally slow working months due to summer vacations.

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 progress in stemming the production and transit of illegal drugs is subject to annual certification by the President of the United States. Although Colombia has received a current certification, there can be no assurance that, in the future, Colombia will receive certification or a national interest waiver. The failure to receive certification or a national interest waiver may result in any of the following:

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

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

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

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

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with the Colombian national oil company and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. There can be no assurance that the United States will not impose sanctions on Colombia in the future, nor can we predict the effect in Colombia that these sanctions might cause.

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

A 40-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups - both funded by the drug trade - continues in Colombia. Insurgents continue to attack civilians and violent guerilla activity continues in many parts of the country.

We, through our acquisition of Argosy Energy International, have interests in three regions of Colombia - in the Middle Magdalena, Llanos and Putumayo regions. The Putumayo region has been prone to guerilla activity in the past. In 1989, Argosy’s facilities in one field were attacked by guerillas and operations were briefly disrupted. Pipelines have also been targets, including the Trans-Andean export pipeline which transports oil from the Putumayo region. In March and April of 2008, sections of one of the Ecopetrol pipelines were blown up by guerillas, which temporarily reduced our deliveries to Ecopetrol in the first quarter of 2008. Ecopetrol has been able to restore deliveries within one to two weeks of these attacks and currently there are no interruptions to our deliveries.

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

Increases in Our Operating Expenses will Impact Our Operating Results and Financial Condition.

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 will 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.

Penalties We May Incur Could Impair Our Business.

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

Environmental Risks May Adversely Affect Our Business.

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

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

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we will obtain 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.

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 expect to operate our business in Argentina, Colombia and Peru, and to expand our operations into other countries in the world. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, interference with private contract rights (such as privatization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates and other laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. Central and South America have 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 other countries in which we intend to operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

For instance, changes in laws in the jurisdiction in which we operate or expand into with the effect of favoring local enterprises, changes in political views regarding the exploitation of natural resources and economic pressures may make it more difficult for us to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations.

Local Legal and Regulatory Systems in Which We Operate May Create Uncertainty Regarding Our Rights and Operating Activities, Which May Harm Our Ability to do Business.

We are a company organized under the laws of the State of Nevada and are subject to United States laws and regulations. The jurisdictions in which we operate our exploration, development and production activities may have different or less developed legal systems than the United States, which may result in risks such as:

effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or, in an ownership dispute, being more difficult to obtain;

a higher degree of discretion on the part of governmental authorities;

the lack of judicial or administrative guidance on interpreting applicable rules and regulations;

inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; and

relative inexperience of the judiciary and courts in such matters.

In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. Property right transfers, joint ventures, licenses, license applications or other legal arrangements pursuant to which we operate may be adversely affected by the actions of government authorities and the effectiveness of and enforcement of our rights under such arrangements in these jurisdictions may be impaired.

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

We are subject to licensing and permitting requirements relating to drilling for oil and natural gas. We may not be able to obtain, sustain or renew such licenses. Regulations and policies relating to these licenses and permits may change or be implemented in a way that we do not currently anticipate. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations.

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.

Foreign Currency Exchange Rate Fluctuations May Affect Our Financial Results.

We expect to sell our oil and natural gas production under agreements that will be denominated in United States dollars and foreign currencies. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. Our production is primarily invoiced in United States dollars, but payment is also made in Argentine and Colombian pesos, at the then-current exchange rate. As a result, we are exposed to translation risk when local currency financial statements are translated to United States dollars, our company’s functional currency. Since we began operating in Argentina (September 1, 2005), the rate of exchange between the Argentine peso and US dollar has varied between 2.89 pesos to one US dollar to 3.23 pesos to the US dollar, a fluctuation of approximately 11%. Exchange rates between the Colombian peso and US dollar have varied between 2,303 pesos to one US dollar to 2,014 pesos to one US dollar since September 1, 2005, a negative fluctuation of approximately 13%. As currency exchange rates fluctuate, translation of the statements of income of international businesses into United States dollars will affect comparability of revenues and expenses between periods.

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

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

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

We 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.

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

On 40 separate dates beginning on April 1, 2008 and ending on June 30, 2008, we sold an aggregate of 10,784,516 shares of our common stock for an aggregate purchase price of $11,157,361. These shares were issued to 136 holders of warrants to purchase shares of our common stock upon exercise of the warrants. The shares were issued to these holders in reliance on Section 4(2) under the Securities Act, in that they were issued to the original purchasers of the warrants, who had represented to us in the private placement of the warrants that they were accredited investors as defined in Regulation D under the Securities Act.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS

At the Annual Meeting of Stockholders of Gran Tierra Energy Inc. held on June 16, 2008, the following proposals were adopted:

Proposal I - To elect the following directors to serve for the ensuing year and until their successors are elected:

	Voted For		Withheld		Broker Non-Votes
Dana Coffield		56,931,427		204,740		¾
Jeffrey Scott		56,870,189		265,978		¾
Walter Dawson		56,898,290		237,877		¾
Verne Johnson		56,829,539		306,628		¾
Nicholas G. Kirton		56,930,614		205,553		¾

Proposal II - To ratify amendments to our Bylaws, as required by the Toronto Stock Exchange, which amendments enable us to comply with the listing requirements of the Toronto Stock Exchange.

Voted For		Voted Against			Abstain			Broker Non-Votes
57,033,157			96,224			6,785			-

Proposal III - To ratify the selection by the Audit Committee of Deloitte & Touche LLP as the independent registered public accounting firm of Gran Tierra Energy Inc. for the fiscal year ending December 31, 2008:

Voted For		Voted Against			Abstain			Broker Non-Votes
56,948,883			180,498			6,785			-

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

SIGNATURES

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

	GRAN TIERRA ENERGY INC.

Date: August 11, 2008	/s/ Dana Coffield
	By: Dana Coffield
	Its: Chief Executive Officer

Date: August 11, 2008	/s/ Martin Eden
	By: Martin Eden
	Its: Chief Financial Officer

EXHIBIT INDEX

Exhibit
No.	Description	Reference
2.1	Arrangement Agreement, dated July 28, 2008, among Gran Tierra Energy Inc., Solana Resources Limited, and Gran Tierra Exchangeco Inc.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2008 (File No.000-52594).

3.1	Articles of Incorporation.	Incorporated by reference to Exhibit 3.1 to the Form SB-2, as amended, filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).

3.2	Certificate Amending Articles of Incorporation.	Incorporated by reference to Exhibit 3.2 to the Form SB-2, as amended, and filed with the Securities and Exchange Commission on December 31, 2003 (File No. 333-111656).

3.3	Certificate Amending Articles of Incorporation.	Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2005 (File No. 333-111656).

3.4	Certificate of Amendment to Articles of Incorporation.	Incorporated by reference to Exhibit 3.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 1, 2006 (File No. 333-111656).

3.5	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 April 11, 2008 (File No.000-52594).

10.10	Form of Indemnity Agreement.	Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 2, 2008 (File No.000-52594).

10.55	Colombian Participation Agreement, dated as of June 22, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.	Filed herewith.

10.56	Amendment No. 1 to Colombian Participation Agreement, dated as of November 1, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.	Filed herewith.

10.57	Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Dana Coffield.	Filed herewith.

10.58	Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Martin Eden.	Filed herewith.

10.59	Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Edgar Dyes.	Filed herewith.

10.60	Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Max Wei.	Filed herewith.

10.61	Employment Agreement, dated June 17, 2008, between Gran Tierra Energy Inc. and Rafael Orunesu.	Filed herewith.

31.1	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer	Filed herewith.

31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer	Filed herewith.

32	Section 1350 Certifications.	Filed herewith.

1. *Definitions.*		1
1.1.	“AAA Rules”	1
1.1A.	“Acceptable Credit Rating”	1
1.2.	“Adjusted Net Revenue Interest”	2
1.3.	“Adjusted New Commercial Field Capital Expenditures”	2
1.4.	“AFE”	2
1.5.	“Affiliate”	2
1.6.	“Allowed Adjustment Factors”	2
1.7.	“ANH”	2
1.8.	“Base Net Revenue Interest”	2
1.9.	“Base Overriding Royalty Interest”	3
1.10.	“Capital Expenditure Commitment”	3
1.11.	“Capital Expenditure Period”	3
1.12.	“Colombia”	3
1.13.	“Colombian Ad Valorem Taxes”	3
1.14.	“Colombian Association Contracts”	3
1.15.	“Colombian Governmental Authorities”	3
1.16.	“Colombian Source Taxes”	3
1.17.	“Confidential Information”	4
1.18.	“Conversion Precondition”	4
1.19.	“Conditional Overriding Royalty”	4
1.20.	“Crosby Arbitration Award”	4
1.21.	“Crosby Escrow Account”	4
1.22.	“Crosby Escrow Agreement”	4
1.23.	“Crosby Escrow Bank”	4
1.24.	“Crosby Final Determination”	4
1.25.	“Crosby Members”	4
1.26.	“Crosby Net Profits Interest”	4
1.27.	“Crosby Net Profits Interest Percentage”	4
1.28.	“Cure Period”	4
1.29.	“Demand”	4
1.30.	“Ecopetrol”	4

1.31.	“Effective Date”	5
1.32.	[INTENTIONALLY DELETED]	5
1.33.	“Historical Properties”	5
1.34.	“Hydrocarbons”	5
1.35.	“Initial Letter of Credit”	5
1.36.	“Initial Term”	5
1.37.	“Issuer Acceptable Credit Rating”	5
1.38.	“Issuer Bank”	5
1.39.	“Letter of Credit”	5
1.40.	“Letter of Credit Default”	5
1.41.	“Material Underpayment”	5
1.42.	“Net Revenue Interest”	5
1.43.	“New Commercial Field”	6
1.44.	“New Commercial Field Capital Expenditures”	6
1.45.	“New Letter of Credit”	6
1.46.	“Operating Expenses”	6
1.47.	“Operator Overhead Costs”	7
1.48.	“Panel”	7
1.49.	“Participation Agreement Dispute”	7
1.50.	“Participation Rights”	7
1.51.	“Payment Default”	7
1.52.	“Person”	7
1.53.	“POPA Prospect Area”	7
1.54.	“Pre-Existing Fields”	8
1.55.	“Prevailing party”	8
1.56.	“Release Covenants”	8
1.57.	“Sales Proceeds”	8
1.58.	“Subsequent Argosy Sale”	8
1.59.	“Subsequent Transfer”	8
1.60.	“U.S. GAAP”	8
1.61.	“Working Interest”	8
2. *Payment Obligation for Base Overriding Royalty.*		8
2.1.	Calculation of Base Overriding Royalty.	8

2.2.	Post-Effective Date Transfers.	9
2.3.	Unitization.	9
3. *Conversion Rights and Payment Obligation for Crosby Net Profits Interest.*		9
3.1.	Right to Convert.	9
3.2.	Calculation of Recovery of Adjusted New Commercial Field Capital Expenditures.	9
3.3.	Calculation of Crosby Net Profits Interest.	9
3.4.	Net Profits Amount and Adjustment.	10
3.5.	Conversion Notice.	10
3.6.	Post-Effective Date Transfers.	10
3.7.	Unitization.	10
3.8.	Pre-Existing Fields.	10
4. *Payment Obligation for Conditional Overriding Royalty*		10
4.1.	Conditional Overriding Royalty Obligations.	10
4.2.	Conditional Overriding Royalty Calculation.	10
4.3.	Post-Effective Date Transfers.	11
4.4.	Unitization.	11
4.5.	Pre-Existing Fields.	11
5. *Capital Expenditure Commitment.*		11
5.1.	5 Year Expenditure Requirement.	11
5.2.	Underinvestment payment.	12
6. *Letter of Credit.*		12
6.1.	Interim Terms Prior To Letter of Credit	12
6.2.	Initial Term for Letter of Credit	12
6.3.	Post-Initial Term	13
6.4.	Replacement Letters of Credit.	15
6.5.	Disbursement of Crosby Escrow Funds.	15
6.6.	Delivery of Old or Replaced Letters of Credit.	16
6.7.	Termination of Section 6.	16
7. *Payments; Reports; Audit Rights.*		16
7.1.	Payments and Reports Regarding Payments.	16
7.2.	Calculation of Payments During First Calendar Year.	18
7.3.	Additional Information Regarding Historical Properties.	19
7.4.	Books and Records.	20

7.5.	Audit.	20
7.6.	Confidentiality.	21
8. *Assignment, Sale or Transfer of Historical Properties by Argosy and/or Sale of Argosy.*		21
8.1.	Subsequent Transfers of Historical Properties.	21
8.2.	Subsequent Sale of Argosy or its Successors.	21
8.3.	Assignment of this Agreement By Argosy or Gran Tierra.	21
8.4.	Prohibited Transfers and Assignments.	23
8.5.	Effect of Transfers and Assignments.	23
8.6.	Release of Gran Tierra, Argosy or Permitted Transferees.	23
9. *Assignment by Crosby.*		23
9.1.	Crosby Members.	23
9.2.	Assignment by Crosby to Non-Members.	24
*10.* *Term; Termination.*		24
10.1.	Base Term; Survival.	24
10.2.	Early Termination.	24
*11.* *Dispute Resolution.*		25
11.1.	Negotiation.	25
11.2.	Arbitration.	25
11.3.	Injunctive Relief.	26
11.4.	Place of Arbitration.	26
11.5.	Legal Fees and Expenses.	26
11.6.	Jurisdiction; Venue.	26
*12.* *Representations and Warranties.*		26
12.1.	Argosy and Gran Tierra.	26
12.2.	Crosby.	27
*13.* *Miscellaneous.*		28
13.1.	Notices.	28
13.2.	Inurement.	29
13.3.	No Other Representations or Warranties.	29
13.4.	Modification; Waiver.	29
13.5.	Entire Agreement.	29
13.6.	Headings.	29
13.7.	Interpretation.	29

13.8.	Further Assurances.	29
13.9.	Governing Law.	30
13.10.	No Liability.	30
13.11.	Force Majeure.	30
13.12.	Survival.	30
13.13.	Counterparts.	30
13.14.	Severability.	30
13.15.	Payments in U.S. Dollars.	30
13.16.	Purchase Agreement.	30

Schedules

Schedule 1.8		Base Net Revenue Interests
Schedule 1.14		Colombian Association Contracts
Schedule 1.33		Historical Properties
Schedule 1.53		POPA Prospect Area Map
Schedule 1.54		Pre-Existing Fields
Schedule 9.1		Crosby Members

Type of Tax		Spanish Name		Colombian income tax treatment
Real Estate tax		Impuesto Predial		Applicable on real estate. Tax based on destination of the property and appraisal. 80% of the tax paid, deductible for income tax purposes.

Type of Tax	Rate			Spanish Name		Colombian income tax treatment
Income Tax Withholding Tax		3.5	%		retencion en la fuente		Set off against final income tax
Remittance Tax		1	%		impuesto de remesas		Set off against final
Withholding*							income tax/remittance tax liability for year
Stamp Tax		1.5	%		impuesto de timbre		Not deductible. No tax setoff

If to Argosy or Gran Tierra:	Gran Tierra Energy Inc.
	300, 611-10 ^th Avenue S.W.
	Calgary, Alberta, Canada, T2R 0B2
	Attn: Dana Coffield
	Facsimile No. (403) 265-3242

With copies to:	McGuire Woods LLP
	1345 Avenue of the Americas
	New York, NY 10105
	Attn: Louis W. Zehil
	Facsimile No. (212) 548-2175

If to Crosby:	Crosby Capital, LLC
	712 Main Street, Suite 1700
	Houston, TX 77002
	Attn: Jay Allen Chaffee
	Facsimile No. (713) 223-5379

With copies to:	Glast, Phillips & Murray, P.C.
	2200 One Galleria Tower
	13355 Noel Road
	Dallas, TX 75240
	Attn: Stanton P. Eigenbrodt
	Facsimile No. (972) 419-8329

ARGOSY ENERGY INTERNATIONAL
By:	Argosy Energy Corp., General Partner

	By:	/s/ Dana Coffield
	Name:	Dana Coffield
	Title:	President

		[illegible]
		Notary Public in and for the Province of Alberta

My Commission Expires:
not applicable

CROSBY CAPITAL, LLC

By:	/s/ Jay Allen Chaffee
	Jay Allen Chaffee
	President

		/s/ Peggy Ann Maltie
		Notary Public in and for the State of Texas

My Commission Expires:		[seal]

July 11, 2007

Colombia Block/Field(a)	Well Name		Royalty Interest			Other Working Interest		Argosy Working Interest		Argosy Net Revenue Interest
Guayuyaco Field: Guayuyaco		Guayuyaco 1 Guayuyaco 2		8.00000 8.00000	(b) (b)		65.00000 65.00000		35.00000 35.00000		32.20000 32.20000

Santana Field: Linda		Linda 1 Linda 2 Linda 3 Linda 4 Linda 5		20.00000 20.00000 20.00000 20.00000 20.00000			65.00000 65.00000 65.00000 65.00000 65.00000		35.00000 35.00000 35.00000 35.00000 35.00000		28.00000 28.00000 28.00000 28.00000 28.00000

Santana Field: Inchiyaco (c)		Inchiyaco 1		20.00000			74.17350		25.82650		20.66120

Santana Field: Mary		Mary 1 Mary 2 Mary 3 Mary 5		20.00000 20.00000 20.00000 20.00000			65.00000 65.00000 65.00000 65.00000		35.00000 35.00000 35.00000 35.00000		28.00000 28.00000 28.00000 28.00000

Santana: Field: Miraflor		Miraflor		20.00000			65.00000		35.00000		28.00000

Santana Field: Toroyaco		Toroyaco 1 Toroyaco 2 Toroyaco 3 Toroyaco 4		20.00000 20.00000 20.00000 20.00000			65.00000 65.00000 65.00000 65.00000		35.00000 35.00000 35.00000 35.00000		28.00000 28.00000 28.00000 28.00000

Colombia Block/Field(a)	Well Name		Royalty Interest			Other Working Interest		Argosy Working Interest		Argosy Net Revenue Interest
Chaza		(d)		8.00000 (b	)		50.00000		50.00000		46.00000
Mecaya		(d)		8.00000 (b	)		85.00000		15.00000		13.80000
Mandiyaco		(d)(e)		8.00000 (b	)		0.00000		100.00000		92.00000
Rio Magdalena		(d)		8.00000 (b	)		65.00000		35.00000		32.20000
Talora		(d)		8.00000 (b	)		80.00000		20.00000		18.40000
Primavera		(d)		8.00000 (b	)		85.00000		15.00000		13.80000

Block	Contractual Documentation	Effective Date
Santana	ECP Risk Sharing Contract	July 27, 1987

Rio Magdalena	ECP Association Contract	February 8, 2002

Guayuyaco	ECP Association Contract	September 20, 2002

Talora	ANH Contract for Exploration and Exploitation of Hydrocarbons	September 16, 2004

Chaza	ANH Contract for Exploration and Exploitation of Hydrocarbons	June 27, 2005

Primavera	ANH Contract for Exploration and Exploitation of Hydrocarbons	May 9, 2006

Mecaya	Application for ANH Contract for Exploration and Exploitation of Hydrocarbons	(1)

Mandiyaco	Application for ANH Contract for Exploration and Exploitation of Hydrocarbons	(2)

Colombia Block/Field	Well Names	Argosy Net Revenue Interest	Description of Historical Property(1)
Block : Santana Fields : Linda Inchiyaco Mary Miraflor Toroyaco	Linda 1 Linda 2 Linda 3 Linda 4 Linda 5 Inchiyaco I Mary 1 Mary 2 Mary 3 Mary 5 Miraflor Toroyaco 1 Toroyaco 2 Toroyaco 3 Toroyaco 4	28.0% 28.0% 28.0% 28.0% 28.0% 20.6612% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28,0% 28.0% 28.0%	The area more specifically described in Annex A of the Amendment to the Santana Shared Risk Contract effective August 14, 2002, attached to this Schedule 1.28 on pages 2 to 28, setting forth the coordinates of the property (a) comprising an area of 21,191 hectares and 5,800 square meters, located in the Guayuyaco Sector in the municipal jurisdictions of Villa Garzón, Puerto Guzman and Mocoa in the Putumayo Province, and the municipal jurisdiction of Santa Rosa in the Cauca Province, and including only (b) (i) the productive areas individually redefined for each of the reservoirs of the Mary, Miraflor, Linda and Toroyaco fields, as described more fully therein; and (ii) the Inchiyaco field which has been determined to be connected to the Mary field.
Block : Guayuyaco Field : Guayuyaco	Guayuyaco 1 Guayuyaco 2	32.2% 32.2%	The area more specifically described in Annex A of the Guayuyaco Adjacent Prospect Contract effective September 20, 2002, attached to this Schedule 1.28 on pages 29 to 39, setting forth the coordinates of the property (a) comprising an area of 21,191 hectares and 5,800 square meters, located in the Guayuyaco Sector in the municipal jurisdictions of Villa Garzón, Puerto Guzmán and Mocoa in the Putumayo Province, and the municipal jurisdiction of Santa Rosa in the Cauca Province, and excluding (b) (i) the productive areas individually redefined for each of the reservoirs of the Mary, Miraflor, Linda and Toroyaco fields, as described more fully therein; and (ii) the Inchiyaco field which has been determined to be connected to the Mary field.
Block : Rio Magdalena	(2)	32.2%	The area more specifically described in Annex A of the Rio Magdalena Association Contract effective February 8, 2002, attached to this Schedule 1.28 on pages 40 to 79, setting forth the coordinates of property comprising an area of 43,841 hectares and 867 square meters, located in the Río Magdalena Sector in the municipal jurisdictions of San Juan de Rioseco, Beltrán, Pulí and Guataqui in the Cundinamarca Province, and the municipal jurisdictions of Guayabal, Lérida, Venadillo, Ambalema and Piedras in the Tolima Province.
Block : Talora	(2)	18.4%	The area more specifically described in Annex A of the Talora Exploration and Exploitation Contract effective September 16, 2004, attached to this Schedule 1.28 on pages 45 to 47, setting forth the coordinates of property comprising an area of 32,472 hectares and 6,893 square meters, located in the Chaza Sector in the municipal jurisdictions of Mocoa and Villagarzón in the Putumayo Province and the municipal jurisdiction of Piamonte in the Cauca Province.

Block : Chaza	(2)	46.0%	The area more specifically described in Annex A of the Chaza Exploration and Exploitation Contract effective June 27, 2005, attached to this Schedule 1.28 on pages 53 to 62, setting forth the coordinates of property comprising an area of 32,472 hectares and 6,893 square meters, located in the Chaza Sector in the municipal jurisdictions of Mocoa and Villagarzón in the Putumayo Province and the municipal jurisdiction of Piamonte in the Cauca Province.
Block : Primavera	(2)	13.8%	The area more specifically described in Annex A of the Primavera Exploration and Exploitation Agreement effective May 9, 2006, setting forth the coordinates of property commonly known as Primavera Block, which description is attached to this Schedule 1.28 on pages 63 to 74.
Block : Mecaya	(2)	13.8%	The area more specifically described in Exhibit I of the Mecaya Commercial Agreement effective May 23, 2006 by and among Expet S.A., Mecaya Colombia Partners LLC and Argosy Energy International, setting forth the coordinates of the Mecaya exploration block in the Putumayo Province of Colombia, which Exhibit I is attached to this Schedule 1.28 op pages 75 to 77.
Block : Mandiyaco	(2)	92.0%	The area more specifically described in the attachment to the application for the Mandiyaco Block with ANH dated April 27, 2006, setting forth the coordinates of the proposed Mandiyaco exploration block in the Cauca Province of Colombia, which such “Mandiyaco Area” attachment is attached to this Schedule 1.28 on pages 78 to 79.

Field Name	Colombian Contract Area	Formation Name	Formation Depth
Linda	Santana Block	Villeta “U”	8688 - 8938
		Villeta “T”	8800 - 8970
		Villeta “N”	8076 - 8345
		Caballos	8991 - 9105

Mary	Santana Block	Villeta “U”	7404 - 7715
		Villeta “T”	7647 - 7882
		Villeta “N”	6894 - 6902
		Caballos	7767 - 8018

Inchiyaco	Santana Block	Villeta “U”	7354 - 7520
		Caballos	7916 - 7976

Miraflor	Santana Block	Villeta “U”	6476 - 6545
		Villeta “T”	6652 - 6798
		Villeta “N”	5868 - 5896
		Caballos	6780 - 6820

Toroyaco	Santana Block	Villeta “U”	8838 - 9100
		Villeta “T”	9036 - 9274
		Villeta “N”	8128 - 8138
		Caballos	9370 - 9396

Guayuyaco	Guayuyaco Block	Villeta “U”	7490 - 7620
		Villeta “T”	7754 - 7790
		Caballos	7882 - 7903

	APPLICANT : GRAN TIERRA ENERGY INC. 300, 611 - 10 ^th Avenue S.W. Calgary, Alberta Canada T2R OBZ
	STATED AMOUNT : USD $4,000,000
	EXPIRY DATE : 31st October, 2007 (save as such date may be extended pursuant to paragraph 9 below) AT OUR COUNTERS
BENEFICIARY : CROSBY CAPITAL, LLC 712 Main Street, Suite 1700 Houston, TX 77002 Attention: Jay Allen Chaffee

ARGOSY ENERGY INTERNATIONAL

By:	/s/ James Hart
Name:	James Hart
Title:	Secretary

GRAN TIERRA ENERGY INC.

By:	/s/ James Hart
Name:	James Hart
Title:	Chief Financial Officer

CROSBY CAPITAL, LLC

By:	/s/ Jay Allen Chaffee
Name:	Jay Allen Chaffee
Title:	President

	APPLICANT : GRAN TIERRA ENERGY INC. 300, 611 — 10 ^th Avenue S.W. Calgary, Alberta Canada T2R OBZ
	STATED AMOUNT : USD $4,000,000
	EXPIRY DATE 31st October, 2007 (save as such date may be extended pursuant to paragraph 9 below) AT OUR COUNTERS

GRAN TIERRA ENERGY INC.		GRAN TIERRA ENERGY INC.

By:	/s/ Martin H. Eden	By:	/s/ Martin H. Eden
	Name: Martin H. Eden		Name: Martin H. Eden
	Title: CFO		Title: CFO

Date:	June 17, 2008	Date:	June 17, 2008

SIGNED, SEALED DELIVERED
In the presence of:

/s/ Sonya Messner		/s/ Dana Coffield
Witness		Dana Quentin Coffield

		Date: 17 June 08

GRAN TIERRA ENERGY INC., an Alberta corporation		GRAN TIERRA ENERGY INC., a Nevada corporation

By:	/s/ Dana Coffield	By:	/s/ Dana Coffield
	Name: Dana Coffield		Name: Dana Coffield
	Title: President and CEO		Title: President and CEO
Date:	17 June 2008	Date:	17 June 08

		EXECUTIVE

		By:	/s/ Martin H. Eden
			Martin H. Eden

		Date:	June 17, 2008

	Gran Tierra Energy Inc., an Alberta Corporation

	By:	/s/ Dana Coffield

	Name:	Dana Coffield

	Title:	President

	Date:	17 June 08

	Gran Tierra Energy Inc., a Nevada corporation

	By:	/s/ Dana Coffield

	Name:	Dana Coffield

	Title:	President

	Date:	17 June 08
/s/ Sonya Messner
Witness		/s/ Edgar Louis Dyes
		Edgar Louis Dyes

	Date:	17 June 08

GRAN TIERRA ENERGY INC., an Alberta corporation

By:	/s/ Dana Coffield
	Name:	Dana Coffield
	Title:	President

Date:	17 June 08

GRAN TIERRA ENERGY INC., a Nevada corporation

By:	/s/ Dana Coffield
	Name:	Dana Coffield
	Title:	President

Date:	17 June 08

Robert Laird	/s/ Max Hsu Wei
Witness	Max Hsu Wei
	Date:	June 17, 2008

	Gran Tierra Argentina S.A., an Argentine corporation

	By:	/s/ Dana Coffield

	Name:	Dana Coffield

	Title:	President

	Date:	17 June 08

	Gran Tierra Energy Inc ., a Nevada corporation

	By:	/s/ Dana Coffield

	Name:	Dana Coffield

	Title:	President

	Date:	17 June 08

/s/ Sonya Messner	/s/ Rafael Orunesu
Witness	Rafael Orunesu

	Date:	17 June 2008

/s/Dana Coffield		/s/ Martin Eden
Dana Coffield		Martin Eden
Chief Executive Officer		Chief Financial Officer