Edgar Filing: GRAN TIERRA ENERGY INC.

GTE - 2012.9.30 - 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012



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

FOR THE TRANSITION PERIOD FROM __________ TO __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)



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

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

(403) 265-3221

(Registrant’s telephone number,

including area code)

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

Indicate by check mark whether the registrant submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý 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 x	Accelerated Filer o
Non-Accelerated Filer o (do not check if a smaller reporting company)	Smaller Reporting Company o

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

On November 2, 2012, the following numbers of shares of the registrant’s capital stock were outstanding: 268,213,818 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 6,223,810 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 7,267,805 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Nine Months Ended September 30, 2012

Table of contents



		Page

PART I

Item 1.	Financial Statements	7

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45

Item 4.	Controls and Procedures	45

PART II

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	47

Item 6.	Exhibits	60

SIGNATURES		60

EXHIBIT INDEX		61

STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q, particularly in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation statements in the 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, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “objective”, “should”, or similar expressions or variations on these 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 or that even if correct, intervening circumstances will not occur to cause actual results to be different than expected. 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. The information included herein is given as of the filing date of this Form 10-Q with the Securities and Exchange Commission (“SEC”) and, 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 forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

In this document, the abbreviations set forth below have the following meanings:



bbl	barrel	BOPD	barrels of oil per day
Mbbl	thousand barrels	Mcf	thousand cubic feet
MMbbl	million barrels	MMcf	million cubic feet
BOE	barrels of oil equivalent	Bcf	billion cubic feet
MMBOE	million barrels of oil equivalent	NGL	natural gas liquids
BOEPD	barrels of oil equivalent per day	NAR	net after royalty

NGL volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices.

In the discussion that follows we discuss our interests in wells and/or acres in gross and net terms. Gross oil and natural gas wells or acres refer to the total number of wells or acres in which we own a working interest. Net oil and natural gas wells or acres are determined by multiplying gross wells or acres by the working interest that we own in such wells or acres. Working interest refers to the interest we own in a property, which entitles us to receive a specified percentage of the proceeds of the sale of oil and natural gas, and also requires us to bear a specified percentage of the cost to explore for, develop and produce that oil and natural gas. A working interest owner that owns a portion of the working interest may participate either as operator, or by voting its percentage interest to approve or disapprove the appointment of an operator, in drilling and other major activities in connection with the development of a property.

We also refer to royalties and farm-in or farmout transactions. Royalties include payments to governments on the production of oil and gas, either in kind or in cash. Royalties also include overriding royalties paid to third parties. Our reserves, production volumes and sales are reported net after deduction of royalties. Production volumes are also reported net of inventory adjustments. Farm-in or farmout transactions refer to transactions in which a portion of a working interest is sold by an owner of an oil and gas property. The transaction is labeled a farm-in by the purchaser of the working interest and a farmout by the seller of the working interest. Payment in a farm-in or farmout transaction can be in cash or in kind by committing to perform and/or pay for certain work obligations.

In the petroleum industry, geologic settings with proven petroleum source rocks, migration pathways, reservoir rocks and traps are referred to as petroleum systems.

Several items that relate to oil and gas operations, including aeromagnetic and aerogravity surveys, seismic operations and several kinds of drilling and other well operations, are also discussed in this document.

Aeromagnetic and aerogravity surveys are a remote sensing process by which data is gathered about the subsurface of the earth. An airplane is equipped with extremely sensitive instruments that measure changes in the earth's gravitational and magnetic field. Variations as small as 1/1,000th in the gravitational and magnetic field strength and direction can indicate structural changes below the ground surface. These structural changes may influence the trapping of hydrocarbons. These surveys are an inexpensive way of gathering data over large regions.

Seismic data is used by oil and natural gas companies as their principal source of information to locate oil and natural gas deposits, both for exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computer software applications are then used to process the raw data to develop an image of underground formations. 2-D seismic is the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. 3-D seismic data is collected using a grid of energy sources, which are generally spread over several square miles. A 3-D seismic survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

Wells drilled are classified as exploration, development, injector or stratigraphic. An exploration well is a well drilled in search of a previously undiscovered hydrocarbon-bearing reservoir. A development well is a well drilled to develop a hydrocarbon-bearing reservoir that is already discovered. Exploration and development wells are tested during and after the drilling process to determine if they have oil or natural gas that can be produced economically in commercial quantities. If they do, the well will be completed for production, which could involve a variety of equipment, the specifics of which depend on a number of technical geological and engineering considerations. If there is no oil or natural gas (a “dry” well), or there is oil and natural gas but the quantities are too small and/or too difficult to produce, the well will be abandoned. Abandonment is a completion operation that involves closing or “plugging” the well and remediating the drilling site. An injector well is a development well that will be used to inject fluid into a reservoir to increase production from other wells. A stratigraphic well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. These wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if drilled in an unknown area or “development type” if drilled in a known area.

Workover is a term used to describe remedial operations on a previously completed well to clean, repair and/or maintain the well for the purposes of increasing or restoring production. It could include well deepening, plugging portions of the well, working with cementing, scale removal, acidizing, fracture stimulation, changing tubulars or installing/changing equipment to provide artificial lift.

The SEC definitions related to oil and natural gas reserves, per Regulation S-X, reflecting our use of deterministic reserve estimation methods, are as follows:

•

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

•

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.


i.	The area of the reservoir considered as proved includes:


A.	The area identified by drilling and limited by fluid contacts, if any, and


B.	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.


ii.	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.


iii.	Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.


iv.	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:


A.	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and


B.	The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.


•	Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.


i.	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

ii.

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.


iii.	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.


iv.	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of section 210.4-10(a) of Regulations S-X.


•	Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.


i.	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total

quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.


ii.	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.


iii.	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.


iv.	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

vi.

Pursuant to paragraph (a)(22)(iii) of section 210.4-10(a) of Regulations S-X, where direct observation has defined a HKO elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

•

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.


•	Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

PART 1

Item 1 - Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations and Retained Earnings (Unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUE AND OTHER INCOME
Oil and natural gas sales	$	168,616		$	150,824		$	438,406		$	434,784
Interest income	317			209			1,628			888
	168,933			151,033			440,034			435,672
EXPENSES
Operating	36,295			21,727			88,115			61,283
Depletion, depreciation, accretion and impairment (Note 5)	45,044			49,852			137,982			160,174
General and administrative	12,896			16,316			46,394			46,364
Equity tax (Note 8)	—			—			—			8,271
Financial instruments gain (Note 3)	—			—			—			(1,522		)
Gain on acquisition (Note 3)	—			—			—			(21,699		)
Foreign exchange (gain) loss	(1,315		)	(15,921		)	27,867			3,773
	92,920			71,974			300,358			256,644

INCOME BEFORE INCOME TAXES	76,013			79,059			139,676			179,028
Income tax expense (Note 8)	(31,408		)	(29,974		)	(82,280		)	(84,663		)
NET INCOME AND COMPREHENSIVE INCOME	44,605			49,085			57,396			94,365
RETAINED EARNINGS, BEGINNING OF PERIOD	197,805			103,377			185,014			58,097
RETAINED EARNINGS, END OF PERIOD	$	242,410		$	152,462		$	242,410		$	152,462

NET INCOME PER SHARE — BASIC	$	0.16		$	0.18		$	0.20		$	0.35
NET INCOME PER SHARE — DILUTED	$	0.16		$	0.17		$	0.20		$	0.34
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	281,695,212			277,608,572			280,387,484			272,006,775
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	284,605,162			284,026,236			283,968,384			279,485,895

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	September 30,		December 31,
	2012		2011
ASSETS
Current Assets
Cash and cash equivalents	$	127,591	$	351,685
Restricted cash	2,734		1,655
Accounts receivable	171,935		69,362
Inventory (Note 5)	21,599		7,116
Taxes receivable	20,431		21,485
Prepaids	2,510		3,597
Deferred tax assets (Note 8)	3,499		3,029
Total Current Assets	350,299		457,929

Oil and Gas Properties (using the full cost method of accounting)
Proved	680,789		618,982
Unproved	428,827		417,868
Total Oil and Gas Properties	1,109,616		1,036,850
Other capital assets	9,274		7,992
Total Property, Plant and Equipment (Note 5)	1,118,890		1,044,842

Other Long-Term Assets
Restricted cash	33,852		13,227
Deferred tax assets (Note 8)	9,307		4,747
Taxes receivable	1,547		—
Other long-term assets	6,553		3,454
Goodwill	102,581		102,581
Total Other Long-Term Assets	153,840		124,009
Total Assets	$	1,623,029	$	1,626,780
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	55,551	$	82,189
Accrued liabilities	67,186		66,832
Taxes payable	35,602		95,482
Asset retirement obligation (Note 7)	41		326
Total Current Liabilities	158,380		244,829

Long-Term Liabilities
Deferred tax liabilities (Note 8)	197,619		186,799
Equity tax payable (Note 8)	3,498		6,484
Asset retirement obligation (Note 7)	15,353		12,343
Other long-term liabilities	1,946		2,007
Total Long-Term Liabilities	218,416		207,633

Commitments and Contingencies (Note 9)
Subsequent Event (Note 13)
Shareholders’ Equity
Common shares (Note 6) (268,178,818 and 262,304,249 common shares and 13,526,615 and 16,323,819 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2012 and December 31, 2011, respectively)	7,986		7,510
Additional paid in capital	995,837		980,014
Warrants (Note 6)	—		1,780
Retained earnings	242,410		185,014
Total Shareholders’ Equity	1,246,233		1,174,318
Total Liabilities and Shareholders’ Equity	$	1,623,029	$	1,626,780

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended September 30,
	2012			2011
Operating Activities
Net income	$	57,396		$	94,365
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, accretion and impairment	137,982			160,174
Deferred taxes (Note 8)	(8,855		)	(14,727		)
Stock-based compensation (Note 6)	9,854			9,383
Unrealized gain on financial instruments (Note 3)	—			(1,354		)
Unrealized foreign exchange loss (gain)	14,072			(625		)
Settlement of asset retirement obligation (Note 7)	(404		)	(309		)
Equity tax	(3,534		)	2,741
Gain on acquisition (Note 3)	—			(21,699		)
Net change in assets and liabilities from operating activities
Accounts receivable and other long-term assets	(96,656		)	(90,014		)
Inventory	(9,769		)	4
Prepaids	1,087			224
Accounts payable and accrued and other liabilities	(25,960		)	(7,224		)
Taxes receivable and payable	(59,281		)	9,658
Net cash provided by operating activities	15,932			140,597

Investing Activities
(Increase) decrease in restricted cash	(21,704		)	260
Additions to property, plant and equipment	(222,119		)	(252,073		)
Proceeds from disposition of oil and gas property (Note 5)	—			3,253
Cash acquired on acquisition (Note 3)	—			7,747
Proceeds on sale of asset-backed commercial paper (Note 3)	—			22,679
Net cash used in investing activities	(243,823		)	(218,134		)

Financing Activities
Settlement of bank debt (Note 3)	—			(54,103		)
Proceeds from issuance of common shares	3,797			2,582
Net cash provided by (used in) financing activities	3,797			(51,521		)

Net decrease in cash and cash equivalents	(224,094		)	(129,058		)
Cash and cash equivalents, beginning of period	351,685			355,428
Cash and cash equivalents, end of period	$	127,591		$	226,370

Cash	$	99,442		$	84,146
Term deposits	28,149			142,224
Cash and cash equivalents, end of period	$	127,591		$	226,370

Supplemental cash flow disclosures:
Cash paid for interest	$	—		$	1,604
Cash paid for income taxes	$	140,069		$	64,310

Non-cash investing activities:
Non-cash working capital related to property, plant and equipment, end of period	$	33,961		$	26,423

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended			Year Ended
	September 30, 2012			December 31, 2011
Share Capital
Balance, beginning of period	$	7,510		$	4,797
Issue of common shares	476			2,713
Balance, end of period	7,986			7,510

Additional Paid in Capital
Balance, beginning of period	980,014			821,781
Issue of common shares	2,902			142,109
Exercise of warrants (Note 6)	1,590			411
Expiry of warrants (Note 6)	190			—
Exercise of stock options (Note 6)	419			1,990
Stock-based compensation (Note 6)	10,722			13,723
Balance, end of period	995,837			980,014

Warrants
Balance, beginning of period	1,780			2,191
Exercise of warrants (Note 6)	(1,590		)	(411		)
Expiry of warrants (Note 6)	(190		)	—
Balance, end of period	—			1,780

Retained Earnings
Balance, beginning of period	185,014			58,097
Net income	57,396			126,917
Balance, end of period	242,410			185,014

Total Shareholders’ Equity	$	1,246,233		$	1,174,318

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

1. Description of Business

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

2. Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2011, included in the Company’s 2011 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 27, 2012.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2011 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as disclosed below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued. Certain amounts for 2011 have been reclassified to conform to the 2012 presentation. The reclassifications had no effect on net income.

Revenue Recognition

Revenue from the production of oil and natural gas is recognized when title passes to the customer and when collection of the revenue is reasonably assured. On February 1, 2012, the sales point for the majority of the Company’s Colombian oil sales in the Putumayo basin changed. Gran Tierra’s customer, Ecopetrol S.A. (“Ecopetrol”), now takes title at the Port of Tumaco on the Pacific coast of Colombia rather than at the entry into the Ecopetrol-operated Trans-Andean oil pipeline (“the OTA pipeline”) at the Orito Station in the Putumayo Basin.

Inventory

Inventory consists of oil in tanks and pipelines and supplies and is valued at the lower of cost or market value. The cost of inventory is determined using the weighted average method. Oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities and includes operating, depletion and depreciation expenses and cash royalties.

Adopted Accounting Pronouncements

Goodwill

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, "Intangibles – Goodwill and Other (Topic 350)." The update is intended to simplify how entities test goodwill for impairment. The update permits entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the two-step goodwill impairment test. This ASU was effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements

Disclosure about Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11, "Balance Sheet – Disclosure about Offsetting Assets and Liabilities (Topic 210)." The update requires an entity to disclose information about offsetting assets and liabilities and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after January 1, 2013. The implementation of this update is not expected to materially impact the Company’s disclosure.

3. Business Combination

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

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

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

The fair value of Gran Tierra’s common shares was determined as the closing price of the common shares of Gran Tierra as at the Acquisition Date.

The fair value of the Replacement Warrants was estimated on the Acquisition Date using the Black-Scholes option pricing model with the following assumptions:



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

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

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

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



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

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

As shown above, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra recognized a gain of $21.7 million, which was reported as “Gain on acquisition” in the condensed consolidated statement of operations. The gain reflected the impact on Petrolifera’s pre-acquisition market value of a lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.

As part of the assets acquired and included in the net working capital in the allocation of the consideration transferred, the Company assigned $22.5 million in fair value to investments in notes that Petrolifera received in exchange for asset-backed commercial paper (“ABCP”) with a face value of $31.3 million. On March 28, 2011, these notes were sold to an unrelated party for proceeds of $22.7 million after the associated line of credit was settled. When combined with the gain arising on expiry of the Replacement Warrants, the financial instruments gain for the nine months ended September 30, 2011 was $1.5 million.

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

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

Gran Tierra also assumed a reserve-backed credit facility upon the Petrolifera acquisition with an outstanding balance of $31.3 million. The amount outstanding under this credit facility was included as part of net working capital in the allocation of consideration transferred. The credit facility

bore interest at LIBOR plus 8.25% and was partially secured by the pledge of the shares of Petrolifera’s subsidiaries. The outstanding balance was repaid when the Argentine restriction preventing its repayment expired on August 5, 2011, resulting in a total debt repayment of $54.1 million,

when combined with the repayment of the CDN$22.5 million ABCP line of credit. Interest expense on the credit facility for the 140-day period from the Acquisition Date to August 5, 2011, was $1.6 million. This amount is recorded on the condensed consolidated statements of operations as part of general and administrative (“G&A”) expenses.

Pro forma results for the nine months ended September 30, 2011 are shown below, as if the acquisition had occurred on January 1, 2010. Pro forma results are not indicative of actual results or future performance.



	Nine Months Ended September 30,
(Thousands of U.S. Dollars, except per share amounts)	2011
Revenue and other income	$	444,867
Net income	$	61,542
Net income per share - basic	$	0.23
Net income per share - diluted	$	0.22

The supplemental pro forma earnings of Gran Tierra for the nine months ended September 30, 2011 were adjusted to exclude $4.4 million of acquisition costs recorded in G&A expenses and the $21.7 million gain on acquisition because they are not expected to have a continuing impact on Gran Tierra’s results of operations. The condensed consolidated statement of operations for the nine months ended September 30, 2011 included revenue of $22.3 million from Petrolifera for the period subsequent to the Acquisition Date. Petrolifera incurred a loss after tax of $2.8 million in the period from the Acquisition Date to September 30, 2011.

4. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia, Argentina, Peru and Brazil based on geographic organization. The level of activity in Brazil was not significant at September 30, 2012 or December 31, 2011; however, the Company has separately disclosed its results of operations in Brazil as a reportable segment. The All Other category represents the Company’s corporate activities.

The accounting policies of the reportable segments are the same as those described in Note 2. The Company evaluates reportable segment performance based on income or loss before income taxes. The segmented results include the operations of Petrolifera subsequent to March 18, 2011, the Acquisition Date (Note 3).

The following tables present information on the Company’s reportable segments and other activities:



	Three Months Ended September 30, 2012
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	145,610	$	22,332		$	—		$	674		$	—		$	168,616
Interest income	171		10			—			40			96			317
Depletion, depreciation, accretion and impairment	35,255		9,165			68			305			251			45,044
Depletion, depreciation, accretion and impairment - per unit of production	24.46		26.60			—			40.35			—			25.12
Income (loss) before income taxes	79,915		1,777			(847		)	(1,170		)	(3,662		)	76,013
Segment capital expenditures	$	35,880	$	11,568		$	11,204		$	2,838		$	300		$	61,790
	Three Months Ended September 30, 2011
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	133,475	$	15,189		$	—		$	2,160		$	—		$	150,824
Interest income	130		(22		)	6			8			87			209
Depletion, depreciation, accretion and impairment	34,915		6,509			7,375			830			223			49,852
Depletion, depreciation, accretion and impairment - per unit of production	25.53		21.62			—			38.74			—			29.50
Income (loss) before income taxes	96,503		(1,623		)	(8,432		)	(592		)	(6,797		)	79,059
Segment capital expenditures	$	40,100	$	7,099		$	4,096		$	7,013		$	255		$	58,563
	Nine Months Ended September 30, 2012
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	376,261	$	59,183		$	—		$	2,962		$	—		$	438,406
Interest income	598		96			15			607			312			1,628
Depletion, depreciation, accretion and impairment	90,625		23,080			1,174			22,379			724			137,982
Depletion, depreciation, accretion and impairment - per unit of production	24.96		24.54			—			708.76			—			29.98
Income (loss) before income taxes	182,516		2,568			(4,147		)	(24,467		)	(16,794		)	139,676
Segment capital expenditures	$	98,476	$	28,412		$	43,866		$	44,536		$	695		$	215,985
	Nine Months Ended September 30, 2011
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	399,252	$	33,038		$	—		$	2,494		$	—		$	434,784
Interest income	375		6			140			19			348			888
Depletion, depreciation, accretion and impairment	104,560		13,161			40,838			1,082			533			160,174
Depletion, depreciation, accretion and impairment - per unit of production	26.33		20.12			—			42.54			—			34.45
Income (loss) before income taxes	228,118		(5,152		)	(43,428		)	(3,336		)	2,826			179,028
Segment capital expenditures (1)	$	136,580	$	25,859		$	29,670		$	35,687		$	1,359		$	229,155

(1) Net of proceeds from the farmout of a 50% working interest in the Santa Victoria Block in Argentina in March 2011 (Note 5).

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.

The Company has two significant customers in Colombia. Sales to Ecopetrol accounted for 71% and 87% of the Company’s revenues for the three months ended September 30, 2012 and 2011, and 77% and 87% for the nine months ended September 30, 2012 and 2011, respectively. For the three months ended September 30, 2012, the Company had an additional short-term significant customer to which deliveries were made between June and August 2012, which accounted for 13% of the Company's revenues during the period.

The Company has two significant customers in Argentina, Shell C.A.P.S.A. (“Shell”) and Refineria del Norte S.A. (“Refiner”). Sales to Shell and Refiner accounted for 4% and 7% of the Company’s oil and natural gas sales for the three months ended September 30, 2012, and 3% and 6% for the nine months ended September 30, 2012, respectively. In the three and nine months ended September 30, 2011, sales to Shell and Refiner each accounted for 3%.



(Thousands of U.S. Dollars)	As at September 30, 2012
	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	819,820	$	134,786	$	76,996	$	84,124	$	3,164	$	1,118,890
Goodwill	102,581		—		—		—		—		102,581
Other assets	243,124		46,383		12,416		11,467		88,168		401,558
Total Assets	$	1,165,525	$	181,169	$	89,412	$	95,591	$	91,332	$	1,623,029

	As at December 31, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	816,396	$	129,072	$	34,305	$	61,875	$	3,194	$	1,044,842
Goodwill	102,581		—		—		—		—		102,581
Other assets	269,843		34,672		9,597		17,065		148,180		479,357
Total Assets	$	1,188,820	$	163,744	$	43,902	$	78,940	$	151,374	$	1,626,780

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



	As at September 30, 2012							As at December 31, 2011
(Thousands of U.S. Dollars)	Cost		Accumulated depletion, depreciation and impairment			Net book value		Cost		Accumulated depletion, depreciation and impairment			Net book value
Oil and natural gas properties
Proved	$	1,383,070	$	(702,281	)	$	680,789	$	1,181,503	$	(562,521	)	$	618,982
Unproved	428,827		—			428,827		417,868		—			417,868
	1,811,897		(702,281		)	1,109,616		1,599,371		(562,521		)	1,036,850
Furniture and fixtures and leasehold improvements	7,581		(5,008		)	2,573		6,973		(4,002		)	2,971
Computer equipment	11,218		(5,102		)	6,116		8,443		(4,174		)	4,269
Automobiles	1,371		(786		)	585		1,295		(543		)	752
Total Property, Plant and Equipment	$	1,832,067	$	(713,177	)	$	1,118,890	$	1,616,082	$	(571,240	)	$	1,044,842

Depletion and depreciation expense on property, plant and equipment for the nine months ended September 30, 2012 was $120.8 million (nine months ended September 30, 2011 - $118.4 million) and for the three months ended September 30, 2012 was $43.0 million (three months ended September 30, 2011 - $41.2 million). A portion of depletion and depreciation expense was recorded as inventory in each period.

On August 7, 2012, the Company announced that Costayaco Field proved reserves as of June 30, 2012, net after royalty ("NAR") and calculated in accordance with SEC rules increased, after production for the six months ended June 30, 2012, by 33% from year-end 2011 reserves to approximately 19.6 million barrels of oil. The reserve revisions were due to a successful waterflood program and effective reservoir management.

On June 5, 2012, the Company received regulatory approval of a farm-in agreement on a block in Colombia. This approval triggered a payment of $21.1 million related to drilling costs for a previously drilled oil exploration well, which was recorded as a capital expenditure in the second quarter of 2012.

Effective June 1, 2012, the Company entered into an agreement to acquire the remaining 40% working interest in a block in Peru. The block is an unproved property. Purchase consideration was $5.4 million and was recorded as a capital expenditure in the three months ended June 30, 2012. The agreement is subject to government approval.

On August 26, 2010, the Company entered into an agreement to acquire a 70% working interest in four blocks in Brazil. With the exception of one block which has a producing well, the remaining blocks are unproved properties. The agreement was effective September 1, 2010, subject to regulatory approvals, and the transaction was completed on June 15, 2011. Purchase consideration was $40.1 million and was recorded as capital expenditures in 2011 and 2010. On January 20, 2012, the Company entered into an agreement to acquire the remaining 30% working interest in these four blocks and, on October 8, 2012, received regulatory approval and acquired the remaining 30% working interest (Note 13).

In September 2011, the Company announced two farmout agreements with Statoil do Brasil Ltda. ("Statoil") in a joint venture with PetróleoBrasileiro S.A., in Brazil’s deepwater offshore Camamu-Almada Basin, pursuant to which, the Company would receive an assignment of a non-operated 10% working interest in Block BM-CAL-7 and a non-operated 15% working interest in Block BM-CAL-10. Both blocks are located in the Camamu Basin, offshore Bahia, Brazil.

During the first quarter of 2012, the Company received regulatory approval from Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP") for the Block BM-CAL-7 farmout agreement. Purchase consideration of $0.7 million was paid and the assignment became effective on April 3, 2012. This block is an unproved property.

On February 17, 2012, in accordance with the terms of the farmout agreement for BM-CAL-10, the Company gave notice to Statoil that it would not enter into and assume its share of the work obligations of the second exploration period of the block. As a result, the farmout agreement terminated and the Company will not receive any interest in this block. Pursuant to the farmout agreement, the Company was obligated to make payment for a certain percentage of the costs relating to Block BM-CAL-10, which relate primarily to a well that was drilled during the term of the farmout agreement. The notice of withdrawal was a trigger for payment of amounts that would otherwise have been due if the farmout agreement had closed and the Company had acquired a working interest. In the three months ended March 31, 2012, the Company recorded a ceiling test impairment loss in the Company’s Brazil cost center of $20.2 million. This impairment charge resulted from the recognition of $23.8 million of capital expenditures in relation to the Block BM-CAL-10 farmout agreement in the first quarter of 2012.

In the nine months ended September 30, 2011, the Company recorded a ceiling test impairment loss in the Company’s Peru cost center of $40.8 million (three months ended September 30, 2011 - $7.4 million). This impairment charge related to drilling costs from a dry well and seismic costs on blocks which were relinquished.

In March 2011, the Company recorded proceeds of $3.3 million from the farmout of a 50% interest in the Santa Victoria Block in Argentina to Apache Corporation.

The amounts capitalized in each of the Company's cost centers during the nine months ended September 30, 2012 and 2011, respectively, were as follows:



	Nine Months Ended September 30, 2012
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	9,279	$	3,480	$	3,670	$	2,653	$	19,082
Capitalized stock-based compensation	$	376	$	275	$	—	$	216	$	867

	Nine Months Ended September 30, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	4,786	$	1,609	$	464	$	1,066	$	7,925
Capitalized stock-based compensation	$	304	$	189	$	—	$	133	$	626

Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at September 30, 2012, the Company had $253.1 million (December 31, 2011 - $274.8 million) of unproved assets in Colombia, $49.9 million (December 31, 2011 - $57.0 million) of unproved assets in Argentina, $76.3 million (December 31, 2011 - $33.7 million) of unproved assets in Peru, and $49.5 million (December 31, 2011 - $52.4 million) of unproved assets in Brazil for a total of $428.8 million (December 31, 2011 - $417.9 million). These properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.

Inventory

As at September 30, 2012, oil and supplies inventories were $19.2 million and $2.4 million, respectively (December 31, 2011 - $4.7 million and $2.4 million, respectively).

6. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share, and two shares are designated as special voting stock, par value $0.001 per share.

As at September 30, 2012, outstanding share capital consists of 268,178,818 common voting shares of the Company, 7,302,805 exchangeable shares of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013, and 6,223,810 exchangeable shares of Goldstrike Exchange Co. (the "Goldstrike exchangeable shares"), automatically exchangeable on November 10, 2013. The exchangeable shares of Gran Tierra Exchange Co., were issued upon acquisition of Solana Resources Limited (“Solana”). The Goldstrike exchangeable shares were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. On October 5, 2012, the automatic redemption date on the Goldstrike exchangeable shares was extended by one year to November 10, 2013. As at September 30, 2012, 95.8% of the Goldstrike exchangeable shares were held by directors and management of the Company. Each exchangeable share is exchangeable into one common voting share of the Company.

The holders of common voting shares are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the Company’s board of directors, in its discretion, declares from legally available funds. The holders of common voting shares have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the common voting shares. Holders of exchangeable shares have substantially the same rights as holders of common voting shares.

Stock Options

For the nine months ended September 30, 2012, the stock-based compensation expense was $10.7 million (nine months ended September 30, 2011- $10.0 million) of which $8.9 million (nine months ended September 30, 2011 - $8.5 million) was recorded in G&A expenses, $0.9 million was recorded in operating expense (nine months ended September 30, 2011 – $0.9 million) and $0.9 million was capitalized as part of exploration and development costs (nine months ended September 30, 2011 – $0.6 million).

For the three months ended September 30, 2012, the stock-based compensation expense was $3.3 million (three months ended September 30, 2011- $3.8 million) of which $2.6 million (three months ended September 30, 2011 - $3.1 million) was recorded in G&A expenses, $0.3 million was recorded in operating expense (three months ended September 30, 2011 – $0.4 million) and $0.4 million was capitalized as part of exploration and development costs (three months ended September 30, 2011 – $0.3 million).

At September 30, 2012, there was $11.2 million (December 31, 2011 - $11.7 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next 3 years.

On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the number of shares of common stock available for issuance thereunder from 23,306,100 shares to 39,806,100 shares. The following table provides information about stock option activity for the nine months ended September 30, 2012:



	Number of Outstanding Options		Weighted Average Exercise Price $/Option
Balance, December 31, 2011	12,864,002		$	4.90
Granted in 2012	3,300,650		5.79
Exercised in 2012	(284,341	)	(3.14		)
Forfeited in 2012	(289,980	)	(6.95		)
Balance, September 30, 2012	15,590,331		$	5.08

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.



	Nine Months Ended September 30,
	2012

Dividend yield (per share)	Nil
Volatility	72	%
Risk-free interest rate	0.3	%
Expected term	4-6 years

The weighted average grant date fair value for options granted in the nine months ended September 30, 2012, was $3.36 (nine months ended September 30, 2011 - $4.96) and for the three months ended September 30, 2012, was $2.62 (three months ended September 30, 2011 - $3.38).

Warrants

At December 31, 2011, the Company had 6,298,230 warrants outstanding to purchase 3,149,115 common shares for $1.05 per share, expiring between June 20, 2012, and June 30, 2012. During the nine months ended September 30, 2012, 2,775,334 common shares were issued upon the exercise of 5,550,668 warrants (nine months ended September 30, 2011, 735,817 common shares were issued upon the exercise of 1,471,634 warrants), 26,190 common shares were issued with 7,143 shares withheld in lieu of a cashless exchange upon the exercise of 66,666 warrants, and 680,896 warrants expired unexercised.

Weighted Average Shares Outstanding



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Weighted average number of common and exchangeable shares outstanding	281,695,212		277,608,572		280,387,484		272,006,775
Shares issuable pursuant to warrants	—		2,597,140		235,582		2,743,224
Shares issuable pursuant to stock options	5,643,730		4,350,662		5,947,880		5,504,270
Shares assumed to be purchased from proceeds of stock options	(2,733,780	)	(530,138	)	(2,602,562	)	(768,374	)
Weighted average number of diluted common and exchangeable shares outstanding	284,605,162		284,026,236		283,968,384		279,485,895

For the three months ended September 30, 2012, 9,957,585 options (three months ended September 30, 2011 - 4,040,996 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. For the nine months ended September 30, 2012, 9,808,758 options (nine months ended September 30, 2011, 3,665,996 options) were excluded from the diluted income per share calculation as the options were anti-dilutive.

7. Asset Retirement Obligation

As at September 30, 2012, the Company’s asset retirement obligation comprised a Colombian obligation in the amount of $6.3 million (December 31, 2011 - $5.5 million), an Argentine obligation in the amount of $6.4 million (December 31, 2011 - $6.7 million), a Brazilian obligation in the amount of $0.5 million (December 31, 2011 - $0.5 million) and a Peruvian obligation in the amount of $2.2 million (December 31, 2011 - $nil). As at September 30, 2012, the undiscounted asset retirement obligation was $46.9 million (December 31, 2011 - $35.7 million). Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:



	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2012			December 31, 2011
Balance, beginning of period	$	12,669		$	4,807
Settlements	(404		)	(345		)
Disposal	—			(172		)
Liability incurred	2,994			867
Liability assumed in a business combination (Note 3)	—			4,901
Foreign exchange	(9		)	17
Accretion	760			673
Revisions in estimated liability	(616		)	1,921
Balance, end of period	$	15,394		$	12,669

Asset retirement obligation - current	$	41		$	326
Asset retirement obligation - long-term	15,353			12,343
Balance, end of period	$	15,394		$	12,669

8. Taxes

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



	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2012			2011
Income before income taxes	$	139,676		$	179,028
	35		%	35		%
Income tax expense expected	48,887			62,660
Foreign currency translation adjustments	8,025			(1,100		)
Impact of foreign taxes	2,716			(4,704		)
Stock-based compensation	3,277			2,987
Increase in valuation allowance	9,304			33,404
Branch and other foreign loss pick-up in the United States and Canada	(4,358		)	(4,627		)
Non-deductible third party royalty in Colombia	9,951			6,145
Non-taxable gain on acquisition	—			(7,595		)
Other permanent differences	4,478			(2,507		)
Total income tax expense	$	82,280		$	84,663

Current income tax	91,135			99,390
Deferred tax recovery	(8,855		)	(14,727		)
Total income tax expense	$	82,280		$	84,663

For the nine months ended September 30, 2012, other permanent differences include $8.2 million of loss adjustments which are fully offset by a change in the valuation allowance.



	As at
(Thousands of U.S. Dollars)	September 30, 2012			December 31, 2011
Deferred Tax Assets
Tax benefit of loss carryforwards	$	75,684		$	63,910
Tax basis in excess of book basis	14,939			17,065
Foreign tax credits and other accruals	28,137			27,164
Capital losses	5,062			2,433
Deferred tax assets before valuation allowance	123,822			110,572
Valuation allowance	(111,016		)	(102,796		)
	$	12,806		$	7,776

Deferred tax assets - current	$	3,499		$	3,029
Deferred tax assets - long-term	9,307			4,747
	12,806			7,776
Deferred Tax Liabilities
Long-term - book value in excess of tax basis	(197,619		)	(186,799		)
Net Deferred Tax Liabilities	$	(184,813	)	$	(179,023	)

As at September 30, 2012, the Company had operating loss carryforwards of $288.9 million (December 31, 2011 - $361.6 million) and capital losses of $35.3 million (December 31, 2011 – $13.7 million) before valuation allowance. Of these operating loss carryforwards and capital losses, $287.3 million (December 31, 2011 - $339.8 million) were losses generated by the foreign subsidiaries of the Company. In certain jurisdictions, the operating loss carryforwards expire between 2013 and 2032 and the capital losses expire between 2013 and 2017, while certain other

jurisdictions allow operating losses to be carried forward indefinitely. Of the total operating loss carryforwards, $3.4 million will expire in 2013.

As at September 30, 2012 and December 31, 2011, the total amount of Gran Tierra’s unrecognized tax benefit was approximately $20.5 million, a portion of which, if recognized, would affect the Company’s effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the condensed consolidated statement of operations. As at September 30, 2012 and December 31, 2011, the amount of interest and penalties on the unrecognized tax benefit included in current income tax liabilities in the condensed consolidated balance sheet was approximately $1.6 million. The Company had no material interest or penalties included in the condensed consolidated statement of operations for the three and nine months ended September 30, 2012 and 2011, respectively.

Changes in the Company's unrecognized tax benefit are as follows:



	Nine Months Ended September 30,
	2012		2011
(Thousands of U.S. Dollars)
Unrecognized tax benefit at beginning of period	$	20,500	$	4,175
Changes for positions relating to prior year	—		(257		)
Additions to tax position related to the current year	—		16,758
Unrecognized tax benefit at end of period	$	20,500	$	20,676

The Company and its subsidiaries file income tax returns in the U.S. and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for the tax years 2005 through 2011 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.

Equity tax for the nine months ended September 30, 2011 of $8.3 million represented a Colombian tax of 6% and was calculated based on the Company’s Colombian segment’s balance sheet equity for tax purposes at January 1, 2011. The tax is payable in eight semi-annual installments over four years, but was expensed in the first quarter of 2011 at the commencement of the four-year period. The equity tax liability at September 30, 2012 and December 31, 2011, was also partially related to an equity tax liability assumed upon the acquisition of Petrolifera.

9. Commitments and Contingencies

Purchase Obligations, Firm Agreements and Leases

The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancellable lease terms in excess of one year as of September 30, 2012:



	As at September 30, 2012
	Payments Due in Period
	Total		Less than 1 Year		1 to 3 years		3 to 5 years		More than 5 years
(Thousands of U.S. Dollars)
Oil transportation services	$	31,283	$	7,259	$	6,811	$	6,811	$	10,402
Drilling and geological and geophysical	42,738		39,484		3,254		—		—
Completions	28,589		23,077		5,512		—		—
Facility construction	31,949		16,134		15,815		—		—
Operating leases	6,008		2,663		3,237		108		—
Software and telecommunication	2,770		1,614		1,089		67		—
Consulting	1,298		1,298		—		—		—
Total	$	144,635	$	91,529	$	35,718	$	6,986	$	10,402

Indemnities

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated. The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.

Letters of credit

At September 30, 2012, the Company had provided promissory notes totaling $32.8 million (December 31, 2011 - $20.7 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts.

Contingencies

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

Gran Tierra’s production from the Costayaco field is subject to an additional royalty that applies when cumulative gross production from a commercial field is greater than five million barrels. This additional royalty is calculated on the difference between a trigger price defined by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) and the sales price. The ANH has requested that the additional compensation be paid with respect to production from wells relating to the Moqueta discovery and has initiated a non-compliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, Gran Tierra views the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that it is clear that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. Discussions with the ANH have not resolved this issue and Gran Tierra has sent notice to the ANH to initiate the dispute resolution process prescribed by the Chaza Contract. As at September 30, 2012, total cumulative production from the Moqueta field was 0.7 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $13.1 million. At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

Gran Tierra is subject to a third party 10% net profits interest on 50% of Gran Tierra's production from the Chaza Block that arises from the original acquisition in 2006 of 50% of Gran Tierra's interest in the Chaza Block Contract. There was a disagreement between Gran Tierra and the third party as to the calculation of the net profits interest. Gran Tierra and the third party agreed to resolve this issue through arbitration. The arbitration was heard in Texas, in accordance with the rules of the American Arbitration Association, in the fourth quarter of 2011. Gran Tierra received the arbitrator's decision on May 24, 2012. The arbitrator ruled against Gran Tierra and as a result $10.9 million became payable in relation to past production. The arbitrator's decision will also increase future net profit interests payable to this third party, but is not expected to have a material impact on future results.

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

10. Financial Instruments, Fair Value Measurements and Credit Risk

At September 30, 2012, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable and accrued liabilities. The fair value of long-term restricted cash approximates its carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. At September 30, 2012, the Company did not have any financial assets or liabilities measured at fair value on the balance sheet and held no derivative instruments. The Company does not use derivative financial instruments for speculative purposes.

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and accounts receivables. The carrying value of cash and accounts receivable reflects management’s assessment of credit risk.

At September 30, 2012, cash and cash equivalents and restricted cash included balances in savings and checking accounts, as well as term deposits and certificates of deposit, placed primarily with governments and financial institutions with strong investment grade ratings, or the equivalent in the Company’s operating areas. Any foreign currency transactions are conducted on a spot basis, with major financial institutions in the Company’s operating areas.

Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues 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. 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. For the nine months ended September 30, 2012, the Company had one significant customer for its Colombian oil, Ecopetrol. For the three months ended September 30, 2012, the Company had an additional short-term significant customer to which deliveries were made between June and August 2012. In Argentina, the Company had two significant customers, Shell and Refiner.

Additionally, foreign exchange gains and losses mainly result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, monetary liabilities, which are mainly denominated in the local currency of the Colombian foreign operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $101,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

11. Bank Debt and Credit Facilities

Effective July 30, 2010, a subsidiary of Gran Tierra, Solana, established a credit facility with BNP Paribas for a three-year term which may be extended or amended by agreement between the parties. This reserve-based facility has a maximum borrowing base up to $100 million and was supported by the present value of the petroleum reserves of two of the Company’s subsidiaries with operating branches in Colombia, Gran Tierra Colombia and Solana Petroleum Exploration (Colombia) Ltd ("Solana Colombia"), and the Company's subsidiary in Brazil - Gran Tierra Energy Brasil Ltda. Subsequent to September 30, 2012, Solana Colombia merged into Petrolifera Petroleum (Colombia) Limited ("PPCL") and continued as PPCL. Upon completion of the merger, the facility is held by PPCL and the underlying reserves continue to support the facility. The initial committed borrowing base was $20 million. Effective August 2, 2012, the committed borrowing base was increased to $50 million. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus 3.5%. In addition, a stand-by fee of 1.5% per annum is charged on the unutilized balance of the committed borrowing base and is included in G&A expenses. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. As at September 30, 2012 and December 31, 2011, the Company had not drawn down any amounts under this facility. On May 17, 2012, BNP Paribas sold Solana’s credit facility to Wells Fargo Bank National Association, as part of the sale of its North American reserve-based lending business, without any modification to the facility.

12. Related Party Transactions

On January 12, 2011, the Company entered into an agreement to sublease office space to a company of which Gran Tierra’s President and Chief Executive Officer serves as an independent director. The term of the sublease was from February 1, 2011 to January 30, 2013 and the sublease payment was $4,500 per month plus approximately $4,700 of operating and other expense; however, subsequent to September 30, 2012, the lease was modified to terminate October 31, 2012 so that Gran Tierra can use this office space.

On August 3, 2010, Gran Tierra entered into a contract related to the Peru drilling program with a company for which one of Gran Tierra’s directors is a shareholder and director. During the three and nine months ended September 30, 2011, $0.2 million and $2.2 million was incurred and capitalized under these contracts. During the three and nine months ended September 30, 2012, $nil was incurred and capitalized under this contract.

On February 1, 2009, the Company entered into a sublease for office space with a company, of which one of Gran Tierra’s directors is a shareholder and director. The term of the sublease ran from February 1, 2009 to August 31, 2011 and the sublease payment was $8,000 per month plus approximately $4,700 for operating and other expenses.

13. Subsequent Event

On October 8, 2012, the Company received regulatory approval and acquired the remaining 30% working interest in four blocks in Brazil pursuant to the terms of a purchase and sale agreement dated January 20, 2012. With the exception of one block which has a producing well, the remaining blocks are unproved properties.

The Company paid initial cash purchase consideration of $28.0 million and an interim period purchase price adjustment of $7.7 million, representing the 30% share of all benefits and costs with respect to the period between the effective date and the completion of the transaction. Contingent consideration up to an additional $3.0 million may be payable dependent on production volumes from the acquired blocks.

The acquisition will be accounted for as a business combination using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed will be recognized at their fair values as at October 8, 2012, the acquisition date, and the results of the blocks will be included with those of Gran Tierra from that date. Fair value estimates are made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

Contingent consideration will be recorded on the balance sheet at the acquisition date fair value based on the consideration expected to be transferred, discounted back to present value by applying an appropriate discount rate that reflected the risk factors associated with the payment streams. The discount rate to be used was determined at the time of measurement in accordance with accepted valuation methods. The acquisition date fair value of the contingent consideration was $1.0 million. The fair value of the contingent consideration will be remeasured at the estimated fair value at each reporting period with the change in fair value recognized as income or expense in operating income. Any changes in fair value will impact earnings in such reporting period until the contingencies are resolved.

The initial accounting for the business combination is incomplete and, therefore, the Company has not disclosed the amounts recognized as of the acquisition date for each major class of assets acquired and liabilities assumed.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q.

The following discussion of our financial condition and results of operations should be read in conjunction with the Financial Statements as set out in Part I – Item 1 of this Quarterly Report on Form 10-Q as well as the financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K, filed with the U.S. Securities and Exchange Commission (“SEC”) on February 27, 2012.

Overview

We are an independent international energy company incorporated in the United States and engaged in oil and natural gas acquisition, exploration, development and production. Our operations are carried out in South America in Colombia, Argentina, Peru, and Brazil, and we are headquartered in Calgary, Alberta, Canada. For the nine months ended September 30, 2012, 86% (nine months ended September 30, 2011 - 92%) of our revenue and other income was generated in Colombia.

Highlights



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012		2011		% Change		2012		2011		% Change
Production (BOEPD) (1)	19,491		18,369		6		16,797		17,033		(1	)

Prices Realized - per BOE	$	94.03	$	89.25	5		$	95.26	$	93.50	2

Revenue and Other Income ($000s)	$	168,933	$	151,033	12		$	440,034	$	435,672	1

Net Income ($000s)	$	44,605	$	49,085	(9	)	$	57,396	$	94,365	(39	)

Net Income Per Share - Basic	$	0.16	$	0.18	(11	)	$	0.20	$	0.35	(43	)

Net Income Per Share - Diluted	$	0.16	$	0.17	(6	)	$	0.20	$	0.34	(41	)

Funds Flow From Operations ($000s) (2)	$	89,935	$	72,817	24		$	206,511	$	227,949	(9	)

Capital Expenditures ($000s)	$	61,790	$	58,563	6		$	215,985	$	229,155	(6	)



	As at
	September 30, 2012		December 31, 2011		% Change
Cash & Cash Equivalents ($000s)	$	127,591	$	351,685	(64	)

Working Capital (including cash & cash equivalents) ($000s)	$	191,919	$	213,100	(10	)

Property, Plant & Equipment ($000s)	$	1,118,890	$	1,044,842	7

(1) Production represents production volumes NAR adjusted for inventory changes. NGL volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and

oil. The rate is not necessarily indicative of the relationship between oil and gas prices.

(2) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under generally accepted accounting principles in the United States of America (“GAAP”). Management uses this financial measure to analyze operating performance and the income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze operating performance and our financial results. Investors should be cautioned that this measure should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with GAAP. Our method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. Funds flow from operations, as presented, is net income adjusted for depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred taxes, stock-based compensation, unrealized gain on financial instruments, unrealized foreign exchange gain or loss, settlement of asset retirement obligation, equity tax and gain on acquisition. A reconciliation from net income to funds flow from operations is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2012			2011			2012			2011
Net income	$	44,605		$	49,085		$	57,396		$	94,365
Adjustments to reconcile net income to funds flow from operations
DD&A expenses	45,044			49,852			137,982			160,174
Deferred taxes	1,195			(5,977		)	(8,855		)	(14,727		)
Stock-based compensation	2,932			3,438			9,854			9,383
Unrealized gain on financial instruments	—			—			—			(1,354		)
Unrealized foreign exchange (gain) loss	(2,092		)	(20,071		)	14,072			(625		)
Settlement of asset retirement obligation	—			—			(404		)	(309		)
Equity tax	(1,749		)	(3,510		)	(3,534		)	2,741
Gain on acquisition	—			—			—			(21,699		)
Funds flows from operations	$	89,935		$	72,817		$	206,511		$	227,949

Highlights

•

In the third quarter of 2012, oil and natural gas production, NAR and adjusted for inventory changes, averaged 19,491 BOEPD, an increase of 6% over the third quarter of 2011. The increase was primarily due to production from new producing wells in Colombia and Argentina and inventory reductions in Colombia during the quarter, partially offset by the impact of oil delivery restrictions during disruptions in the Ecopetrol-operated Trans-Andean oil pipeline (“the OTA pipeline”) in Colombia. For the nine months ended September 30, 2012, oil and gas production, NAR and adjusted for inventory changes, decreased by 1% to 16,797 BOEPD compared with the corresponding period in 2011. Production during the nine months ended September 30, 2012 was impacted by an increase in oil inventory in the OTA pipeline as a result of the change in the sales point in Colombia and oil delivery restrictions as a result of OTA pipeline disruptions.

•

Revenue and other income increased by 12% to $168.9 million in the third quarter of 2012 compared with $151.0 million in the third quarter of 2011 due to increased production, NAR and adjusted for inventory changes, and increased realized prices. The average price realized in the third quarter of 2012 was $94.03 per BOE, an increase of 5% compared with $89.25 per BOE in the third quarter of 2011. For the nine months ended September 30, 2012, revenue and other income were comparable with the corresponding period in 2011. The average price realized per BOE of $95.26, which increased by 2% from the comparable period in 2011, was impacted by the settlement of a third party royalty dispute in Colombia which reduced the average realized price by $2.37 per BOE.

•

Net income was $44.6 million in the third quarter of 2012, representing basic and diluted net income per share of $0.16. This compares with net income of $49.1 million, or $0.18 per share basic and $0.17 per share diluted in the third quarter of 2011. In the third quarter of 2012, higher oil and natural gas sales and lower DD&A and G&A expenses were more than offset by increased operating and income tax expenses and a decrease in foreign exchange gains. Net income decreased by 39% to $57.4 million, or $0.20 per share basic and diluted, for the

nine months ended September 30, 2012, compared with $94.4 million, or $0.35 per share basic and $0.34 per share diluted, in the comparable period of 2011. In the nine months ended September 30, 2012, increased oil and natural gas sales, decreased DD&A and income tax expenses and the absence of the Colombian equity tax expense were more than offset by increased operating expenses and foreign exchange losses and the absence of the comparable period gain on acquisition of Petrolifera Petroleum Limited ("Petrolifera").

•

Funds flow from operations increased by 24% to $89.9 million in the third quarter of 2012 from $72.8 million in the comparable quarter of 2011. The increase was primarily due to higher oil and natural gas sales and decreased G&A expenses, partially offset by increased operating and income tax expenses. For the nine months ended September 30, 2012, funds flow from operations decreased by 9% from $227.9 million to $206.5 million primarily due to increased operating expenses and realized foreign exchange losses, partially offset by lower income tax expenses.

•

Cash and cash equivalents were $127.6 million at September 30, 2012, compared with $351.7 million at December 31, 2011. The change in cash and cash equivalents during the nine months ended September 30, 2012 was primarily the result of funds flow from operations of $206.5 million and proceeds from issuance of common shares of $3.8 million being more than offset by an increase in assets and liabilities from operating activities of $190.6 million, capital expenditures of $222.1 million and a $21.7 million increase in restricted cash related to the pending 30% working interest acquisition in Brazil.

•

Working capital (including cash and cash equivalents) was $191.9 million at September 30, 2012, a $21.2 million decrease from December 31, 2011. The decrease was primarily a result of a $224.1 million decrease in cash and cash equivalents, partially offset by a $102.6 million increase in accounts receivable due to the timing of collection of Ecopetrol receivables, a $14.5 million increase in inventory primarily due to the new sales agreement in Colombia which changed the sales point from Orito Station to the Port of Tumaco, a $59.9 million decrease in taxes payable due to the payment of 2011 income taxes in Colombia, and a $25.9 million decrease in accounts payable, accrued liabilities and other due to the payment of royalties and indirect taxes.


•	Property, plant and equipment at September 30, 2012, was $1.1 billion, an increase of $74.0 million from December 31, 2011, as a result of $216.0 million of capital expenditures (excluding changes in non-cash working capital) partially offset by $142.0 million of depletion, depreciation and impairment expenses.

Business Environment Outlook

Our revenues have been significantly affected by pipeline disruptions in Colombia and the continuing fluctuations in oil prices. Oil prices are volatile and unpredictable and are influenced by concerns about financial markets and the impact of the worldwide economy on oil demand growth.

We believe that our current operations and 2012 capital expenditure program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline further due to unforeseen events, including additional pipeline delivery restrictions in Colombia or a downturn in oil and gas prices, we would examine measures such as further capital expenditure program reductions, periodic draws from our revolving credit facility, issuance of debt, disposition of assets, or issuance of equity. The continuing uncertainty regarding the Middle East and North Africa, continued economic instability in the United States and Europe and the decline in Chinese economic growth is having an impact on world markets, and we are unable to determine the impact, if any, these events may have on oil prices and demand.

Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt markets. Should we be required to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of our common shares. Our ability to utilize our common shares to raise capital may be negatively affected by declines in the price of our common shares. Also, raising funds by issuing shares or other equity securities would further dilute our existing shareholders, and this dilution would be exacerbated by a decline in our share 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 and will expose us to interest

rate risk. Depending on the currency used to borrow money, we may also be exposed to further foreign exchange risk. Our ability to borrow money and the interest rate we pay for any money we borrow will be affected by market conditions, and we cannot predict what price we may pay for any borrowed money.

Business Combination

On March 18, 2011, we completed the acquisition of all the issued and outstanding common shares and warrants of Petrolifera pursuant to the terms and conditions of an arrangement agreement dated January 17, 2011. Petrolifera is a Calgary-based oil, natural gas and NGL exploration, development and production company active in Argentina, Colombia and Peru. For further details reference should be made to Note 3 of the interim unaudited condensed consolidated financial statements.

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

As indicated in the allocation of the consideration transferred, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, we reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, we recognized a gain on acquisition of $21.7 million in the interim unaudited condensed consolidated statement of operations. The gain reflected the impact on Petrolifera’s pre-acquisition market value resulting from their lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.

Consolidated Results of Operations



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011			% Change		2012			2011			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	168,616		$	150,824		12		$	438,406		$	434,784		1
Interest income	317			209			52		1,628			888			83
	168,933			151,033			12		440,034			435,672			1

Operating expenses	36,295			21,727			67		88,115			61,283			44
DD&A expenses	45,044			49,852			(10	)	137,982			160,174			(14	)
G&A expenses	12,896			16,316			(21	)	46,394			46,364			—
Equity tax	—			—			-		—			8,271			(100	)
Financial instruments gain	—			—			-		—			(1,522		)	(100	)
Gain on acquisition	—			—			-		—			(21,699		)	(100	)
Foreign exchange (gain) loss	(1,315		)	(15,921		)	(92	)	27,867			3,773			639
	92,920			71,974			29		300,358			256,644			17

Income before income taxes	76,013			79,059			(4	)	139,676			179,028			(22	)
Income tax expense	(31,408		)	(29,974		)	5		(82,280		)	(84,663		)	(3	)
Net income	$	44,605		$	49,085		(9	)	$	57,396		$	94,365		(39	)

Production

Oil and NGL's, bbl	1,726,224			1,604,242			8		4,410,917			4,492,430			(2	)
Natural gas, Mcf	401,783			514,086			(22	)	1,148,440			945,240			21
Total production, BOE (1)	1,793,188			1,689,923			6		4,602,324			4,649,970			(1	)

Average Prices

Oil and NGL's per bbl	$	96.75		$	92.76		4		$	98.42		$	96.02		2
Natural gas per Mcf	$	4.01		$	3.92		2		$	3.75		$	3.64		3

Consolidated Results of Operations per BOE

Oil and natural gas sales	$	94.03		$	89.25		5		$	95.26		$	93.50		2
Interest income	0.18			0.12			50		0.35			0.19			84
	94.21			89.37			5		95.61			93.69			2

Operating expenses	20.24			12.86			57		19.15			13.18			45
DD&A expenses	25.12			29.50			(15	)	29.98			34.45			(13	)
G&A expenses	7.19			9.65			(25	)	10.08			9.97			1
Equity tax	—			—			-		—			1.78			(100	)
Financial instruments gain	—			—			-		—			(0.33)			(100	)
Gain on acquisition	—			—			-		—			(4.67)			(100	)
Foreign exchange (gain) loss	(0.73)			(9.42)			(92	)	6.05			0.81			647
	51.82			42.59			22		65.26			55.19			18

Income before income taxes	42.39			46.78			(9	)	30.35			38.50			(21	)
Income tax expense	(17.52)			(17.74)			(1	)	(17.88)			(18.21)			(2	)
Net income	$	24.87		$	29.04		(14	)	$	12.47		$	20.29		(39	)

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

Net income was $44.6 million, or $0.16 per share basic and diluted, for the third quarter of 2012 compared with net income of $49.1 million, or $0.18 per share basic and $0.17 per share diluted, for the comparable quarter in 2011. In the third quarter of 2012, higher oil and natural gas sales due to increased production in Colombia and Argentina, increased average realized oil prices and increased sales from oil inventory in Colombia and lower DD&A and G&A expenses, were more than offset by increased operating and income tax expenses, and lower foreign exchange gains.

For the nine months ended September 30, 2012, net income was $57.4 million, a 39% decrease from the comparable period in 2011. On a per share basis, net income decreased to $0.20 per share basic and diluted from $0.35 per share basic and $0.34 per share diluted in the comparable period in 2011. For the nine months ended September 30, 2012, increased oil and natural gas sales, decreased DD&A and income tax expenses and the absence of the Colombian equity tax expense were more than offset by increased operating expenses and foreign exchange losses and the absence of the comparable period gain on acquisition. Net income in the comparable period in 2011 included a gain on the acquisition of Petrolifera of $21.7 million.

Oil and NGL production, NAR and adjusted for inventory changes, for the third quarter of 2012 increased to 1.7 MMbbl compared with 1.6 MMbbl for the comparable quarter in 2011 primarily due to production from new wells in Colombia and Argentina and increased sales from oil inventory in Colombia, partially offset by 36 days of oil delivery restrictions resulting from disruptions in the OTA pipeline in Colombia. We continued production at a reduced rate while the OTA pipeline was down, selling a portion of our oil through trucking and storing excess oil.

Oil and NGL production, NAR and adjusted for inventory changes, for the nine months ended September 30, 2012 decreased to 4.4 MMbbl compared with 4.5 MMbbl for the comparable period in 2011 due to pipeline disruptions and the effect of a change in the sales point in Colombia. As a result of entering into new oil sales and transportation agreements with Ecopetrol as of February 1, 2012, which changed the sales point of our oil from Orito station to the Port of Tumaco, our oil inventory increased and now includes oil in the OTA pipeline and associated Ecopetrol owned facilities. Production during the nine months ended September 30, 2012 reflects approximately 121 days of oil delivery restrictions in Colombia.

Average realized oil prices in the third quarter of 2012 increased by 4% to $96.75 per bbl from $92.76 per bbl in the third quarter of 2011 and increased by 2% to $98.42 per bbl from $96.02 per bbl for the nine months ended September 30, 2012. We received a premium to West Texas Intermediate (“WTI”) in Colombia during the nine months ended September 30, 2012. WTI oil prices for the three and nine months ended September 30, 2012 were $92.27 and $96.21 per bbl, respectively, compared with $89.70 and $95.40 per bbl in the comparable periods in 2011. Average Brent oil prices for the three and nine months ended September 30, 2012 were $109.61 and $112.20 per bbl.

Increased production and increased average realized oil prices resulted in a 12% increase in revenue and other income to $168.9 million for the third quarter of 2012 compared with $151.0 million in the comparable quarter in 2011. Revenue and other income for the nine months ended September 30, 2012 increased to $440.0 million from the comparable period in 2011 as a result of increased realized prices partially offset by decreased production.

Operating expenses for the third quarter of 2012 amounted to $36.3 million, or $20.24 per BOE, compared with $21.7 million, or $12.86 per BOE, in the comparable quarter in 2011. The increase in operating expenses was due to an increase of $13.8 million in Colombia, primarily due to OTA pipeline oil transportation costs of $3.77 per BOE, which were previously deducted from realized sales prices, now included as operating costs due to the change in sales point in February 2012, and increased trucking due to OTA pipeline disruptions.

Operating expenses for the nine months ended September 30, 2012 amounted to $88.1 million, or $19.15 per BOE, compared with $61.3 million, or $13.18 per BOE, in the comparable period of 2011. The increase in operating expenses for the nine months ended September 30, 2012 was primarily due to an increase of $19.6 million in Colombia for the reasons stated above as well as higher percentage of production from fields which have higher per BOE operating costs.

DD&A expenses for the third quarter of 2012 were $45.0 million compared with $49.9 million for the comparable quarter in 2011. On a per BOE basis, DD&A expenses in the third quarter of 2012 were $25.12 compared with $29.50 in the comparable period in 2011, representing a 15% decrease. The decrease resulted from increased reserves and lower impairment charges which more than offset increased future development costs in the depletable base. DD&A expenses for the comparable quarter in 2011 included a $7.4 million ceiling test impairment in our Peru cost center relating to Block 128, which we decided to relinquish during that quarter.

For the nine months ended September 30, 2012, DD&A expenses decreased to $138.0 million from $160.2 million in the comparable period in 2011. DD&A expenses for the nine months ended September 30, 2012 included a $20.2 million ceiling test impairment in our Brazil cost center related to seismic and drilling costs on Block BM-CAL-10. DD&A expenses for the comparable period in 2011 included a $40.8 million ceiling test impairment in our Peru cost center relating to drilling costs from a dry well and seismic costs on relinquished blocks. On a per BOE basis, the depletion rate decreased by 13% to $29.98 from $34.45. The decrease was mainly due to lower impairment charges of $4.59 per BOE in the nine months ended September 30, 2012 compared with $8.77 per BOE in the comparable period of 2011.

G&A expenses of $12.9 million for the third quarter of 2012 decreased by 21% from $16.3 million in the comparable quarter in 2011, primarily due to increased recoveries, increased capitalized costs in Peru due to increased exploration and development activity, and the absence of interest expense of $0.8 million relating to the Petrolifera debt, which was repaid in August 2011. These G&A expense reductions were partially offset by increased employee related costs reflecting expanded operations. G&A expenses per BOE in the third quarter in 2012 were 25% lower than in the comparable quarter in 2011 at $7.19 per BOE due to the same factors and increased production.

For the nine months ended September 30, 2012, G&A expenses of $46.4 million were consistent with the comparable period in 2011. Increased employee related costs and bank fees reflecting expanded operations were offset by increased recoveries, the absence of expenses related to the 2011 Petrolifera acquisition and increased capitalized costs in Peru. G&A expenses in the comparable period of 2011 included $1.2 million of expenses associated with the acquisition of Petrolifera and $1.6 million of interest on the Petrolifera debt. G&A expenses per BOE in the nine months ended September 30, 2012 of $10.08 were consistent with the prior year comparable period.

Equity tax in the nine months ended September 30, 2011 represented a Colombian tax of 6% which was calculated based on our Colombian segment’s balance sheet equity at January 1, 2011. The tax is payable in eight semi-annual installments over four years, but was expensed in the first quarter of 2011 at the commencement of the four-year period.

Gain on acquisition of $21.7 million in the nine months ended September 30, 2011 related to the Petrolifera acquisition.

The foreign exchange gain was $1.3 million in the third quarter of 2012 and included an unrealized non-cash foreign exchange gain of $2.1 million. For the comparable quarter in 2011, the foreign exchange gain was $15.9 million and included an unrealized foreign exchange gain of $20.1 million. Unrealized non-cash foreign exchange gains and losses primarily represent foreign exchange gains and losses resulting from the translation of current and deferred tax liabilities in Colombia. The Colombian Peso weakened by 0.9% and 7.3% against the U.S. dollar in the third quarter of 2012 and 2011, respectively.

For the nine months ended September 30, 2012 and 2011, the foreign exchange loss was $27.9 million and $3.8 million, respectively, of which $14.1 million was an unrealized non-cash foreign exchange loss and $0.6 million was an unrealized non-cash foreign exchange gain, respectively. The realized foreign exchange loss in 2012 primarily arose upon payment of 2011 Colombian income tax liabilities. The Colombian Peso strengthened by 7.3% and weakened by 0.1% against the U.S. dollar in the nine months ended September 30, 2012 and 2011, respectively.

Under GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation results in the recognition of unrealized exchange losses or gains.

Income tax expense for the third quarter of 2012 was $31.4 million compared with $30.0 million recorded in the comparable quarter in 2011. The increase was a result of lower income before tax being more than offset by an increase in non-deductible royalty payments and a decrease in valuation allowance.

Income tax expense was $82.3 million for the nine months ended September 30, 2012, compared with $84.7 million recorded in the comparable period in 2011. The decrease was primarily due to lower income before tax. The effective tax rate was 59% in the nine months ended September 30, 2012 compared with 47% in the comparable period in 2011. The change was primarily due to a non-taxable gain on the acquisition of Petrolifera recorded in 2011, an increase in non-deductible royalty payments, the impact of foreign taxes as compared with the U.S. statutory rate, and an increase in the non-deductible foreign currency translation adjustments in 2012. The variance from the 35% U.S. statutory rate for the third quarter of 2011 was primarily attributable to non-deductible foreign currency translation adjustments, non-deductible royalty payments, and an increase in valuation allowances taken on losses incurred in the U.S., Canada, Argentina, Peru and Brazil, partially offset by the inclusion of a non-taxable gain on acquisition.

2012 Work Program and Capital Expenditure Program

Our capital expenditures during the third quarter of 2012 were $61.8 million, bringing total expenditures for the nine months ended September 30, 2012 to $216.0 million compared with $229.2 million for the nine months ended September 30, 2011. In 2012, capital expenditures included drilling expenditures of $141.6 million, acquisitions of $12.5 million, geological and geophysical (“G&G”) expenditures of $36.6 million, facilities expenditures of $11.9 million and other expenditures of $13.4 million.

Our 2012 capital program of $380 million consists of $172 million for Colombia; $94 million for Brazil; $46 million for Argentina; $66 million for Peru; and $2 million associated with corporate activities. Of this, $243 million is for drilling, $48 million is for acquisitions, $30 million is for facilities, pipelines and other, and $59 million is for G&G expenditures. Of the $243 million allocated to drilling, approximately $117 million is for exploration and the balance is for delineation and development drilling.

Our 2012 work program is intended to create both growth and value through strategic acquisitions of working interests, by developing existing assets to increase reserves and production levels, and through the construction of pipelines and facilities in the areas with proved reserves. We are financing our capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and pursue acquisitions. However, as a result of the nature of the oil and natural gas exploration, development and exploitation industry, budgets are regularly reviewed with respect to both the success of expenditures and other opportunities that become available. Accordingly, while we currently intend that funds be expended as set forth in our 2012 work program, there may be circumstances where, for sound business reasons, actual expenditures may in fact differ.

Segmented Results – Colombia



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011			% Change		2012		2011		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	145,610		$	133,475		9		$	376,261	$	399,252	(6	)
Interest income	171			130			32		598		375		59
	145,781			133,605			9		376,859		399,627		(6	)

Operating expenses	27,005			13,222			104		61,200		41,565		47
DD&A expenses	35,255			34,915			1		90,625		104,560		(13	)
G&A expenses	4,504			6,427			(30	)	18,079		15,166		19
Equity tax	—			—			-		—		8,271		(100	)
Foreign exchange (gain) loss	(898		)	(17,462		)	(95	)	24,439		1,947		—
	65,866			37,102			78		194,343		171,509		13

Income before income taxes	$	79,915		$	96,503		(17	)	$	182,516	$	228,118	(20	)

Production

Oil and NGL's, bbl	1,428,251			1,355,661			5		3,606,090		3,939,486		(8	)
Natural gas, Mcf	76,770			70,884			8		144,930		186,456		(22	)
Total production, BOE (1)	1,441,046			1,367,475			5		3,630,245		3,970,562		(9	)

Average Prices

Oil and NGL's per bbl	$	101.81		$	98.07		4		$	104.23	$	101.09	3
Natural gas per Mcf	$	2.62		$	7.37		(64	)	$	2.67	$	5.37	(50	)

Segmented Results of Operations per BOE

Oil and natural gas sales	$	101.04		$	97.61		4		$	103.65	$	100.55	3
Interest income	0.12			0.10			20		0.16		0.09		78
	101.16			97.71			4		103.81		100.64		3

Operating expenses	18.74			9.67			94		16.86		10.47		61
DD&A expenses	24.46			25.53			(4	)	24.96		26.33		(5	)
G&A expenses	3.13			4.70			(33	)	4.98		3.82		30
Equity tax	—			—			-		—		2.08		(100	)
Foreign exchange (gain) loss	(0.62		)	(12.77		)	(95	)	6.73		0.49		—
	45.71			27.13			68		53.53		43.19		24

Income before income taxes	$	55.45		$	70.58		(21	)	$	50.28	$	57.45	(12	)


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

For the third quarter of 2012, income before income taxes from Colombia was $79.9 million compared with $96.5 million in the comparable quarter in 2011. The decrease was due to higher oil and natural gas sales primarily due to higher production, increased sales from oil inventory and higher prices and lower G&A expenses being more than offset by increased operating expenses and decreased foreign exchange gains.

For the nine months ended September 30, 2012, income before income taxes was $182.5 million compared with $228.1 million in the comparable period in 2011. The decrease was due to lower oil and natural gas sales primarily due to reduced production, increased operating and G&A expenses and increased foreign exchange losses, partially offset by lower DD&A expenses and the absence of equity tax expense.

On February 1, 2012, the sales point for the majority of our oil sales in the Putumayo Basin changed. Ecopetrol now takes title at the Port of Tumaco on the Pacific coast of Colombia rather than at the entry into the OTA pipeline. As a result, our reported oil inventory increased, representing ownership of oil in the OTA pipeline and associated Ecopetrol owned facilities. OTA transportation costs were previously factored into the price we received for oil, but, due to the changes in sales point, are now invoiced separately and included in operating costs. This change resulted in an increase in OTA oil transportation costs of $3.77 per bbl during the third quarter of 2012 and is expected to increase transportation costs by $3.73 per bbl for the fourth quarter of 2012, but should be offset by an equivalent increase in the realized price.

For the third quarter of 2012, production of oil and NGLs, NAR and adjusted for inventory changes, increased by 5% to 1.4 MMbbl. Increased production from new producing wells was partially offset by the impact of 36 days of oil delivery restrictions resulting from disruptions in the OTA pipeline in Colombia. Increases in production resulted from the development of the Moqueta field with six producing wells and production in the Garibay Block from the Jilguero-1 and -2 and Melero-1 wells. We continued production at a reduced rate while the OTA pipeline was down, selling a portion of our oil through trucking and storing excess oil. The disruptions resulted in a reduction in oil production of approximately 1,700 BOPD NAR.

Oil and NGL production, NAR and adjusted for inventory changes, for the nine months ended September 30, 2012 decreased to 3.6 MMbbl compared with 3.9 MMbbl for the comparable period in 2011 due to pipeline disruptions and the effect of a change in the sales point. Production during the nine months ended September 30, 2012 reflects approximately 121 days of oil delivery restrictions in Colombia. The disruptions resulted in a reduction in oil production of approximately 4,000 BOPD NAR in the nine months ended September 30, 2012.

Revenue and other income for the third quarter of 2012 increased by 9% to $145.8 million from the comparable period in 2011, and decreased by 6% to $376.9 million for the nine months ended September 30, 2012, as compared with the corresponding period in 2011.

The average realized price per bbl for oil in the three months ended September 30, 2012 increased by 4% to $101.81 compared with the corresponding quarter in 2011. For the nine months ended September 30, 2012, the average realized price per bbl for oil increased by 3% to $104.23 compared with the corresponding period in 2011. As discussed above, effective February 1, 2012, the average realized price per bbl in Colombia increased due to the new sales agreement with Ecopetrol. During the second quarter of 2012, the recognition of additional royalties resulting from an arbitrator's decision on a dispute with a third party relating to the calculation of the third party's net profits interest on 50% of production from the Chaza Block in Colombia resulted in a $10.9 million revenue reduction. This amount related to July 2009 to May 2012 production. The recognition of this royalty resulted in a $3.00 per BOE reduction in the average realized price in the nine months ended September 30, 2012. The decision will increase future net profit interests payable to this third party. The third party royalty settlement represented less than 1% of the reported revenue for the periods under dispute and it is not expected to have a materially different effect on future revenue.

Operating expenses increased by 104% to $27.0 million and 47% to $61.2 million for the three and nine months ended September 30, 2012, respectively, from the comparable periods in 2011. On a per BOE basis, operating expenses increased by 94% to $18.74 and 61% to $16.86 for the three and nine months ended September 30, 2012, respectively. As discussed above, effective February 1, 2012, operating expenses per BOE were higher due to OTA pipeline oil transportation costs now charged as operating costs. Additionally, operating expenses per BOE were higher due to increased trucking as a result of the pipeline disruptions and a higher percentage of production being from the Moqueta, Jilguero and Melero fields, which have higher per BOE operating costs. Workover costs per BOE were consistent with the comparable quarter in 2011.

DD&A expenses increased by 1% to $35.3 million for the third quarter of 2012 from the comparable quarter in 2011. The increase was due to increased production, offset by decreased depletion rates. For the nine months ended September 30, 2012, reduced production and decreased

depletion rates resulted in 13% lower DD&A expenses of $90.6 million. On a per BOE basis, DD&A expenses decreased by 4% to $24.46 and 5% to $24.96 for the three and nine months ended September 30, 2012, respectively. Increased costs in our depletable pools were more than offset by increased reserves.

G&A expenses for the third quarter of 2012 decreased to $4.5 million ($3.13 per BOE) from $6.4 million ($4.70 per BOE) in the comparable quarter in 2011. The decrease was mainly due to higher G&A expense recoveries, partially offset by increased office costs and salaries resulting from an increased headcount due to expanded operations. The decrease per BOE was due to higher production. For the nine months ended September 30, 2012, G&A expenses increased by 19% to $18.1 million ($4.98 per BOE) due to increased salaries, office costs and consulting fees.

Equity tax in the nine months ended September 30, 2011, represented a Colombian tax of 6% on a legislated measure which is based on our Colombian segment’s balance sheet equity at January 1, 2011.

The results for the third quarter of 2012 included a foreign exchange gain of $0.9 million, which included an unrealized foreign exchange gain of $2.2 million. For the comparable quarter in 2011, the foreign exchange gain was $17.5 million, of which $19.4 million was unrealized. For the nine months ended September 30, 2012 and 2011, the foreign exchange loss was $24.4 million and $1.9 million, respectively, of which $14.0 million was an unrealized non-cash foreign exchange loss and $0.1 million was an unrealized non-cash foreign exchange gain, respectively.

Capital Program - Colombia

Capital expenditures in our Colombian segment during the third quarter of 2012 were $35.9 million bringing total expenditures for the nine months ended September 30, 2012, to $98.5 million. The following table provides a breakdown of capital expenditures in 2012 and 2011:



	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of U.S. Dollars)	2012		2011			2012		2011
Drilling and completions	$	23.1	$	26.7		$	63.5	$	83.5
Facilities and equipment	7.0		5.3			17.6		20.3
G&G	3.3		9.3			9.5		14.4
Other	2.5		(1.2		)	7.9		18.4
	$	35.9	$	40.1		$	98.5	$	136.6

During the third quarter of 2012, we commenced drilling one development well in Colombia. The Moqueta-7 development well on the Chaza Block (100 % working interest ("WI"), operated) spud on September 6, 2012, and reached a total depth at 9,295 feet measured depth (“MD”) in basement. Due to encountering additional unexpected oil bearing reservoirs, the well was extended 450 meters, or approximately 1,400 meters southwest of Moqueta-4. A total of 215 feet of potential net pay has been encountered in Moqueta-7, with no oil-water contacts encountered in the main field, nor in the two new fault blocks encountered by the well, based on well cuttings and electric log interpretations. Actual oil pay thicknesses are subject to testing of the reservoirs. This testing has begun and is expected to be completed by the end of November 2012.

Additionally, the Costayaco-16 development well on the Chaza Block, which spud on June 6, 2012, was completed during the quarter and is on production and the La Vega Este-1 oil exploration well on the Azar Block (40 % WI, operated) was plugged and abandoned during the quarter.

We commenced civil works for an oil exploration well in the Turpial Block (50% WI, operated) and an additional development well in the Moqueta field. Facilities work continued on the Costayaco and Moqueta fields and 3D seismic was acquired on the Rumiyaco Block.

Subsequent to September 30, 2012, we were the successful bidder in Colombia's National Hydrocarbon Agency (“ANH”) bid round on the Sinu-1 and Sinu-3 Blocks of the Sinu Basin in northern Colombia. The open and competitive process was available to those pre-qualified by the ANH and bid contracts are expected to be finalized before December 31, 2012. We will become the operator of both blocks, subject to ANH approval. We will hold a 60% WI in the Sinu-1 Block and a 51% WI in the Sinu-3 Block, adjacent to, and immediately east of the Sinu-1 Block.

Outlook - Colombia

The 2012 capital program in Colombia is $172 million with $120 million allocated to drilling, $22 million to facilities and pipelines and $30 million for G&G expenditures.

Our planned work program for the remainder of 2012 in Colombia includes drilling a development well on the Costayaco field and an additional development well on the Moqueta field, one gross oil exploration well on each of the Turpial Block and Sierra Nevada Block (100 % WI, operated) and converting an existing well on the Garibay Block (50 % WI, operated) to a water injector well. Additionally, G&G expenditures are planned for the Chaza, Piedemonte Norte, Garibay and Putumayo-1 Blocks.

Segmented Results – Argentina



	Three Months Ended September 30,							Nine Months Ended September 30,
	2012		2011			% Change		2012		2011			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	22,332	$	15,189		47		$	59,183	$	33,038		79
Interest income	10		(22		)	145		96		6			—
	22,342		15,167			47		59,279		33,044			79

Operating expenses	8,197		7,946			3		24,490		18,921			29
DD&A expenses	9,165		6,509			41		23,080		13,161			75
G&A expenses	2,258		2,389			(5	)	7,268		6,086			19
Foreign exchange loss (gain)	945		(54		)	—		1,873		28			—
	20,565		16,790			22		56,711		38,196			48

Income (loss) before income taxes	$	1,777	$	(1,623	)	209		$	2,568	$	(5,152	)	150

Production

Oil and NGL's, bbl	290,414		227,157			28		773,252		527,507			47
Natural gas, Mcf	325,013		443,202			(27	)	1,003,510		758,784			32
Total production, BOE (1)	344,583		301,024			14		940,504		653,971			44

Average Prices

Oil and NGL's per bbl	$	72.05	$	60.29		20		$	71.48	$	58.00		23
Natural gas per Mcf	$	4.34	$	3.37		29		$	3.90	$	3.22		21

Segmented Results of Operations per BOE

Oil and natural gas sales	$	64.81	$	50.46		28		$	62.93	$	50.52		25
Interest income	0.03		(0.07		)	(143	)	0.10		0.01			900
	64.84		50.39			29		63.03		50.53			25

Operating expenses	23.79		26.40			(10	)	26.04		28.93			(10	)
DD&A expenses	26.60		21.62			23		24.54		20.12			22
G&A expenses	6.55		7.94			(18	)	7.73		9.31			(17	)
Foreign exchange loss (gain)	2.74		(0.18		)	—		1.99		0.04			—
	59.68		55.78			7		60.30		58.40			3

Income (loss) before income taxes	$	5.16	$	(5.39	)	196		$	2.73	$	(7.87	)	135


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

For the three and nine months ended September 30, 2012, income before income taxes in Argentina was $1.8 million and $2.6 million, respectively, compared with loss before income taxes of $1.6 million and $5.2 million in the comparable periods in 2011, respectively. In the three and nine months ended September 30, 2012, increased oil and natural gas sales more than offset increased operating and DD&A expenses and foreign exchange losses.

Total production of oil and gas from the Argentina segment increased by 14% to 0.3 MMBOE in the third quarter of 2012 and by 44% to 0.9 MMBOE for the nine months ended September 30, 2012. The acquisition of Petrolifera on March 18, 2011, added seven blocks in the Neuquen Basin, including production from four blocks, to the Argentina segment. Production in the nine months ended September 30, 2012, included Petrolifera production of 0.5 MMBOE, NAR and adjusted for inventory changes, which was comparable with Petrolifera's production in the nine months ended September 30, 2011.

Oil and NGL production, NAR and adjusted for inventory changes, increased 28% to 0.3 MMbbl for the three months ended September 30, 2012, and increased 47% to 0.8 MMbbl for the nine months ended September 30, 2012 compared with the comparable periods in 2011. The increase was due to production from the Proa-2 well, in the Surubi Block, which began production in April 2012.

Natural gas production, NAR amounted to 0.3 Bcf in the third quarter of 2012 bringing natural gas production year to date to 1.0 Bcf. Natural gas production, NAR, amounted to 0.4 Bcf in the third quarter of 2011.

Revenue and other income increased by 47% to $22.3 million in the third quarter of 2012 and by 79% to $59.3 million for the nine months ended September 30, 2012, due to higher production volumes and increased prices.

Average oil prices increased by 20% in the third quarter of 2012 and 23% in the nine months ended September 30, 2012, compared with the comparable periods in 2011. Due to the Argentine regulatory regime, the average oil price we received for production from our blocks during the third quarter of 2012 was $72.05 per bbl. Currently most oil and gas producers in Argentina are operating without sales contracts for periods longer than several months. We are continuing deliveries to refineries and are negotiating a price for those deliveries on a regular and short-term basis. We have been able to negotiate higher oil prices with refineries as a result of the Argentine government’s decision to allow an increase in domestic petroleum product prices. Prices have now stabilized.

Operating expenses increased by 3% to $8.2 million and 29% to $24.5 million for the three and nine months ended September 30, 2012, respectively, from the comparable periods in 2011. The increase was due to higher production volumes, partially offset by a reduction in the per BOE cost, and nine months versus six months of operating costs relating to the Petrolifera properties included in 2012 results as compared to the prior year. On a per BOE basis, operating expenses decreased by 10% to $23.79 and 10% to $26.04 for the three and nine months ended September 30, 2012, respectively. The reduction in operating costs on a per BOE basis was due to increased production from the Surubi Block, which has lower per BOE operating costs.

DD&A expenses increased by 41% to $9.2 million and 75% to $23.1 million for the three and nine months ended September 30, 2012, respectively, from the comparable periods in 2011. The increase was due to higher production volumes and an increase in the per BOE depletion rate. On a per BOE basis, DD&A expenses increased by 23% to $26.60 and 22% to $24.54 for the three and nine months ended September 30, 2012, respectively, due to a reduction in reserves.

G&A expenses were $2.3 million ($6.55 per BOE) and $7.3 million ($7.73 per BOE) in the three and nine months ended September 30, 2012, respectively, compared with $2.4 million ($7.94 per BOE) and $6.1 million ($9.31 per BOE) in the comparable periods. G&A expenses in the three and nine months ended September 30, 2011 included $0.8 million and $1.6 million, respectively, of interest expense on debt acquired on the Petrolifera acquisition which was repaid in August 2011 when the Argentine requirements allowed it to be repaid. For the three and nine months ended September 30, 2012, salaries related expenses were higher due to an increased headcount as a result of expanded operations.

Capital Program - Argentina

Capital expenditures in our Argentine segment during the third quarter of 2012 were $11.6 million bringing total expenditures for the nine months ended September 30, 2012, to $28.4 million. Third quarter 2012 capital expenditures included drilling expenditures of $8.2 million, G&G expenses of $1.6 million, facilities expenses of $0.7 million and other expenditures of $1.1 million.

During the third quarter of 2012, we commenced drilling one exploration well and seven development wells in Argentina:


•	Drilling commenced on five development wells, PMN 1120, PMN 1122, PMN 1123, PMN 1124 and PMN 1125, on the Puesto Morales Block (100% WI, operated). Four of these wells are producing and one is a water injection well. A sixth development well was spud on October 1, 2012.


•	On the Rinconada Norte Block (35% WI, non-operated), drilling commenced on two development wells, RN.a -1018 and RN.a -1009. These wells are currently being completed. Additionally, together with our partner, we drilled one exploration well, RN.x -1020, which was plugged and abandoned.

Additionally, we successfully completed three workovers on the Puesto Morales Block and one workover on the Rinconada Norte Block. We are optimizing the waterflood program in the developed area of the Sierra Blancas formation.

Outlook – Argentina

The 2012 capital program in Argentina is $46 million with $34 million allocated to drilling, $4 million to facilities and pipelines, and $8 million to G&G expenditures.

Our planned work program for the remainder of 2012 in Argentina includes drilling three development wells on the Puesto Morales Block and workovers on existing wells. We also plan to acquire G&G on the Puesto Morales and Valle Morado Blocks and perform facilities work on the El Chivil Block.

Segmented Results – Peru



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011			% Change		2012			2011			% Change
(Thousands of U.S. Dollars)
Interest income	$	—		$	6		(100	)	$	15		$	140		(89	)

Operating expenses	—			80			(100	)	161			$	252		(36	)
DD&A expenses	68			7,375			(99	)	1,174			40,838			(97	)
G&A expenses	1,034			946			9		3,116			2,511			24
Foreign exchange (gain) loss	(255		)	37			(789	)	(289		)	(33		)	776
	847			8,438			(90	)	4,162			43,568			(90	)

Loss before income taxes	$	(847	)	$	(8,432	)	90		$	(4,147	)	$	(43,428	)	90

DD&A expenses for the third quarter of 2011 and the nine months ended September 30, 2011, included $7.4 million and $40.8 million of impairment charges relating to drilling costs from a dry well and seismic costs on blocks which were relinquished.

G&A expenses were $1.0 million in the third quarter of 2012 compared with $0.9 million in the comparable quarter of 2011 and $3.1 million in the nine months ended September 30, 2012 compared with $2.5 million in the comparable period of 2011. The increases were due to higher salaries expense resulting from expanded operations.

Capital Program – Peru

Capital expenditures in our Peruvian segment during the third quarter of 2012 were $11.2 million, bringing total expenditures for the nine months ended September 30, 2012 to $43.9 million

Third quarter of 2012 capital expenditures included drilling expenditures of $6.6 million, G&G expenses of $2.2 million and other expenditures of $2.4 million.

During the third quarter of 2012, we continued civil construction of a drilling platform and dock facility on Block 95 (increased from 60% to 100% WI, subject to government approval, and operator) in Peru. Additionally, we acquired 2D seismic on this block during the quarter.

Subsequent to September 30, 2012, we assumed 100% WI and operatorship of Blocks 123 and 129, subject to government approval.

Outlook - Peru

The 2012 capital program in Peru is $66 million with $33 million allocated to drilling, $12 million to acquisitions and $21 million for G&G expenditures.

Our planned work program for the remainder of 2012 in Peru includes pre-drilling activities and the commencement of drilling for one exploration well on Block 95, the commencement of an aeromagnetic and aerogravity survey and Environmental Impact Assessments on Block 133 and environmental health and safety programs on all blocks.

Segmented Results - Brazil



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011			% Change		2012			2011			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	674		$	2,160		(69	)	$	2,962		$	2,494		19
Interest income	40			8			400		607			19			—
	714			2,168			(67	)	3,569			2,513			42

Operating expenses	1,093			479			128		2,264			545			315
DD&A expenses	305			830			(63	)	22,379			1,082			—
G&A expenses	355			863			(59	)	1,492			3,528			(58	)
Foreign exchange loss	131			588			(78	)	1,901			694			174
	1,884			2,760			(32	)	28,036			5,849			379

Loss before income taxes	$	(1,170	)	$	(592	)	(98	)	$	(24,467	)	$	(3,336	)	(633	)

Production (1)

Oil and NGL's, bbl	7,559			21,424			(65	)	31,575			25,437			24

Average Prices

Oil and NGL's per bbl	$	89.17		$	100.82		(12	)	$	93.81		$	98.05		(4	)

Segmented Results of Operations per BOE

Oil and natural gas sales	$	89.17		$	100.82		(12	)	$	93.81		$	98.05		(4	)
Interest income	5.29			0.37			—		19.22			0.75			—
	94.46			101.19			(7	)	113.03			98.80			14

Operating expenses	144.60			22.36			547		71.70			21.43			235
DD&A expenses	40.35			38.74			4		708.76			42.54			—
G&A expenses	46.96			40.28			17		47.25			138.70			(66	)
Foreign exchange loss	17.33			27.45			(37	)	60.21			27.28			121
	249.24			128.83			93		887.92			229.95			286

Loss before income taxes	$	(154.78	)	$	(27.64	)	460		$	(774.89	)	$	(131.15	)	491


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

For the three months ended September 30, 2012, loss before income taxes in Brazil was $1.2 million compared with $0.6 million in the comparable period in 2011. For the nine months ended September 30, 2012, loss before income taxes was $24.5 million compared with $3.3 million in the comparable period in 2011. We began recording revenue from production in Brazil from Block 155 in the onshore Recôncavo Basin on June 15, 2011, the date regulatory approval was received for the purchase of our 70% working interest in that block.

Oil and natural gas sales and operating expenses represented sales and operating expenses from Block 155. Oil and natural gas sales in the third quarter of 2012 were lower than the comparable quarter in 2011 as a result of production being shut in between the expiry of the long-term test phase on July 31, 2012 and the declaration of commerciality for the Tiê field. Production recommenced on September 21, 2012 after the receipt of regulatory approval. We were also subject to gas flaring restrictions during the third quarter of 2012, which were subsequently eased and are subject to re-approval for periods after December 31, 2012. For the nine months ended September 30, 2012, production of oil and NGLs, NAR and adjusted for inventory changes, increased by 24% from the comparable period in 2011. The comparative period included production from June 15, 2011 onwards.

Average Brent oil prices for the three and nine months ended September 30, 2012, were $109.61 and $112.20 per bbl. The price we receive in Brazil is at a discount to Brent due to a refining discount.

DD&A expenses in the nine months ended September 30, 2012 included a ceiling test impairment loss of $20.2 million. The impairment loss related to seismic and drilling costs on Block BM-CAL-10.

G&A expenses were $0.4 million and $0.9 million in the third quarter of 2012 and 2011 and $1.5 million and $3.5 million in the nine months ended September 30, 2012 and 2011, respectively. We began recognizing production in Brazil in June 2011 upon receipt of regulatory approval. This resulted in a significant increase in the costs that were directly attributable to operations and exploration and development and a corresponding reduction in G&A expenses compared with the same period in 2011.

Capital Program – Brazil

Capital expenditures in Brazil during the third quarter of 2012 were $2.8 million, bringing total expenditures for the nine months ended September 30, 2012 to $44.5 million. Third quarter 2012 capital expenditures included $1.8 million of drilling expenditures, $0.8 million of facilities expenses and $0.2 million of other expenditures.

On October 8, 2012, we received regulatory approval and acquired the remaining 30% working interest in Blocks 129, 142, 155 and 224 in the Recôncavo Basin in Brazil.

Outlook – Brazil

The 2012 capital program in Brazil is $94 million with $56 million allocated to drilling, $36 million to acquisition costs and $2 million to facilities and pipelines expenditures. We have delayed some drilling activity and facilities work until 2013.

Our planned work program for the remainder of 2012 in Brazil includes drilling two horizontal sidetrack oil exploration wells on Blocks 155 and 142 (100% WI and operator) and facilities work on Block 155.

Results - Corporate Activities



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011			% Change		2012			2011			% Change
(Thousands of U.S. Dollars)
Interest income	$	96		$	87		10		$	312		$	348		(10	)

DD&A expenses	251			223			13		724			533			36
G&A expenses	4,745			5,691			(17	)	16,439			19,073			(14	)
Financial instruments gain	—			—			-		—			(1,522		)	(100	)
Gain on acquisition	—			—			-		—			(21,699		)	(100	)
Foreign exchange (gain) loss	(1,238		)	970			(228	)	(57		)	1,137			(105	)
	3,758			6,884			(45	)	17,106			(2,478		)	790

(Loss) income before income taxes	$	(3,662	)	$	(6,797	)	46		$	(16,794	)	$	2,826		(694	)

G&A expenses in the third quarter of 2012 decreased from $5.7 million in the comparable quarter in 2011 to $4.7 million. For the nine months ended September 30, 2012, G&A expenses were $16.4 million compared with $19.1 million in the comparable period in 2011. In the three and nine months ended September 30, 2012, increases in salaries expenses due to expanded operations were more than offset by an increase in the amount of costs recovered from business units, a reduction in consulting costs and the absence of Petrolifera acquisition costs ($1.2 million in the nine months ended September 30, 2011).

Gain on acquisition in the nine months ended September 30, 2011 related to the acquisition of Petrolifera.

Liquidity and Capital Resources

At September 30, 2012, we had cash and cash equivalents of $127.6 million compared with $351.7 million at December 31, 2011.

We believe that our cash resources, including cash on hand, cash generated from operations and our revolving credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2012, given current oil price trends and production levels. In accordance with our investment policy, cash balances are held in our primary cash management bank, HSBC Bank plc., in interest earning current accounts or are invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.

At September 30, 2012, 77% of our cash and cash equivalents was held by our foreign subsidiaries. This balance is not available to fund domestic operations unless funds are repatriated. We do not intend to repatriate funds, but if we did we would have to accrue and pay taxes. Additionally, 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 payments to us. There may be a tax imposed with respect to the expatriation of the proceeds from our foreign subsidiaries. The Brazilian government has similar regulations in place regarding foreign exchange controls.

Effective July 30, 2010, we established a credit facility with BNP Paribas for a three-year term which may be extended or amended by agreement between the parties. This reserve-based facility has a maximum borrowing base of up to $100 million and is supported by the present value of our Colombian petroleum reserves of two of our subsidiaries with operating branches in Colombia – Gran Tierra Energy Colombia Ltd. and Solana Petroleum Exploration (Colombia) Ltd ("Solana Colombia"), and our subsidiary in Brazil - Gran Tierra Energy Brasil Ltda. Subsequent to September 30, 2012, Solana Colombia merged into Petrolifera Petroleum (Colombia) Limited ("PPCL") and continued as PPCL. Upon completion of the merger, the facility is held by PPCL and the underlying reserves continue to support the facility. The initial committed borrowing base is $20 million and, effective August 2, 2012, the committed borrowing base was increased to $50 million. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus 3.5%. In addition, a stand-by fee of 1.5% per annum is charged on the

unutilized balance of the committed borrowing base and is included in G&A expenses. Under the terms of the facility, we are required to maintain and were in compliance with certain financial and operating covenants. On May 17th, 2012, BNP Paribas sold Solana’s credit facility to Wells Fargo Bank National Association, as part of the sale of its North American reserve-based lending business. At September 30, 2012, and December 31, 2011, we had not drawn down any amounts under this facility.

Cash Flows

During the nine months ended September 30, 2012, our cash and cash equivalents decreased by $224.1 million as a result of cash used in investing activities of $243.8 million, partially offset by cash provided by operating activities of $15.9 million and cash provided by financing activities of $3.8 million.

Cash provided by operating activities in the nine months ended September 30, 2012 was primarily affected by increased operating expenses and realized foreign exchange losses and a $190.6 million increase in assets and liabilities from operating activities. The main changes in assets and liabilities from operating activities were as follows: accounts receivable increased by $96.7 million due to increased oil and gas sales and the timing of collection of receivables; inventory increased by $9.8 million due to the change in sales point under a new sales agreement in Colombia; accounts payable and accrued liabilities decreased by $26.0 million; and taxes payable decreased by $59.3 million due to tax payments in Colombia. The decrease in accounts payable and accrued liabilities was primarily the result of a reduction in royalties payable due to the timing of royalty payments and a reduction in VAT payable.

Cash outflows from investing activities in the third quarter of 2012 included capital expenditures of $222.1 million and an increase in restricted cash of $21.7 million related to the pending 30% working interest acquisition in Brazil.

Cash provided by financing activities in the third quarter of 2012 related to proceeds from issuance of common shares upon the exercise of stock options.

Off-Balance Sheet Arrangements

As at September 30, 2012, we had no off-balance sheet arrangements.

Contractual Obligations



	As at September 30, 2012
	Payments Due in Period
	Total		Less than 1 Year		1 to 3 years		3 to 5 years		More than 5 years
(Thousands of U.S. Dollars)
Oil transportation services	$	31,283	$	7,259	$	6,811	$	6,811	$	10,402
Drilling and geological and geophysical	42,738		39,484		3,254		—		—
Completions	28,589		23,077		5,512		—		—
Facility construction	31,949		16,134		15,815		—		—
Operating leases	6,008		2,663		3,237		108		—
Software and telecommunication	2,770		1,614		1,089		67		—
Consulting	1,298		1,298		—		—		—
Total	$	144,635	$	91,529	$	35,718	$	6,986	$	10,402

At September 30, 2012, we had also provided promissory notes totaling $32.8 million as security for letters of credit relating to work commitment guarantees contained in exploration contracts.

Related Party Transactions

On January 12, 2011, we entered into an agreement to sublease office space to a company of which our President and Chief Executive Officer serves as an independent director. The term of the sublease runs from February 1, 2011, to January 30, 2013, and the sublease payment is $4,500 per month plus approximately $4,700 of operating and other expense; however, subsequent to September 30, 2012, the lease was modified to terminate October 31, 2012 so that we can use this office space.

On August 3, 2010, we entered into a contract related to the Peru drilling program with a company for which one of our directors is a shareholder and director. During the three and nine months ended September 30, 2011, $0.2 million and $2.2 million was incurred and capitalized under this contract. During the three and nine months ended September 30, 2012, $nil was incurred and capitalized under this contract.

On February 1, 2009, we entered into a sublease for office space with a company, of which one of Gran Tierra’s directors is a shareholder and director. The term of the sublease ran from February 1, 2009 to August 31, 2011 and the sublease payment was $8,000 per month plus approximately $4,700 for operating and other expenses.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2011 Annual Report on Form 10-K, filed with the SEC on February 27, 2012, 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. Most of our revenues are from oil sales at prices which are defined by contract relative to WTI or Brent and adjusted for quality 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.

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. dollar price of WTI or Brent oil.

In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars. In Argentina and Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of our capital expenditures within Argentina and Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. The majority of our capital expenditures in Peru are in U.S. dollars. The majority of income and value added taxes and G&A expenses in all locations are in local currency. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

Additionally, unrealized foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $101,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

We consider our exposure to interest rate risk to be immaterial. Our interest rate exposures primarily relate to our investment portfolio. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes. We do not hold equity investments, and we have no debt.

Item 4. - Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(e) of the Exchange Act. Based on their evaluation, our principal executive and principal financial officers have concluded that Gran Tierra's disclosure controls and procedures were effective as of September 30, 2012 to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. Discussions with the ANH have not resolved this issue and Gran Tierra has sent notice to the ANH to initiate the dispute resolution process prescribed by the Chaza Contract. As at September 30, 2012, total cumulative production from the Moqueta field was 0.7 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $13.1 million. At this time, no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

We have several other lawsuits and claims pending for which we currently cannot determine the ultimate result. We record costs as they are incurred or become probable and determinable. We believe the resolution of these matters would not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

The risks relating to our business and industry, as set forth in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the Securities and Exchange Commission on February 27, 2012, are set forth below and are unchanged substantively at September 30, 2012, other than those designated by an asterisk “*”.

Risks Related to Our Business

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

During 2012, the guerrilla activity in Colombia has increased significantly. This increased activity creates a greater risk for our operations and our employees and our mitigation activities may not be adequate to alleviate the risks arising from such guerrilla activity.

For over 40 years, the Colombian government has been engaged in a civil war with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia ("FARC") and the National Liberation Army ("ELN"). Both of these groups have been designated as terrorist organizations by the United States and the European Union. Another threat comes from criminal gangs formed from the former members of the United Self-Defense Forces of Colombia ("AUC") militia, a paramilitary group that originally sprouted up to combat FARC and ELN, which the Colombian government successfully dissolved.

We operate principally in the Putumayo Basin in Colombia, and have properties in other basins, including the Catatumbo, Cauca, Llanos, Middle Magdalena and Lower Magdalena basins. The Putumayo and Catatumbo regions have been the breeding place of guerrilla activity. Beginning in 1989, our predecessor company's facilities in one field were attacked by guerrillas and operations were briefly disrupted. In October 2010, two of our sites in the Putumayo/Cauca were attacked by FARC guerrillas causing some disruption to operations. Pipelines have also been primary targets because such pipelines cannot be adequately secured due to the sheer size of such pipelines and the remoteness of the areas in which the pipelines are laid. The Ecopetrol-operated OTA pipeline which transports oil from the Putumayo region and upon which we materially rely has been a target by these guerrilla groups. In March and April of 2008, June, July, August and October of 2009, June, August, and September of 2010, February 2011, February to August of 2012 and October 2012, sections of the OTA pipeline were sabotaged by guerrillas, which temporarily reduced our deliveries to Ecopetrol during the affected periods. In the nine months ended September 30, 2012, the OTA pipeline was shutdown for over 120 days and the shutdown has had a material adverse effect on our deliveries to Ecopetrol and our financial performance for 2012. Such disruptions may continue indefinitely.

Continuing attempts by the Colombian government to reduce or prevent guerrilla activity may not be successful and guerrilla activity may continue to disrupt our operations in the future. Our efforts to increase security measures may not be successful and there can also be no assurance that we can maintain the safety of our field and Bogota head office personnel or operations in Colombia or that this violence will not continue to adversely affect our operations in the future and cause significant loss.

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

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

from the Putumayo basin in Colombia, and we depend on the OTA pipeline to transport our oil to market. Cash flow from these sales funds a large part of our business. Disruptions to this pipeline, as described in the risk "We May Encounter Difficulties Storing and Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses" could harm our business in Colombia and other countries.

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

To sell the oil and natural gas that we are able to produce, we have to make arrangements for storage and distribution to the market. We rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. In certain areas, we may be required to rely on only one gathering system, trucking company or pipeline, and, if so, our ability to market our production would be subject to their reliability and operations. These factors may affect our ability to explore and develop properties and to store and transport our oil and gas production, and may increase our expenses. Furthermore, future instability in one or more of the countries in which we operate, weather conditions or natural disasters, actions by companies doing business in those countries, labor disputes or actions taken by the international community may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

The majority of our oil in Colombia is delivered by a single pipeline to Ecopetrol and sales of oil have been and could continue to be disrupted by damage to this pipeline or displaced by Ecopetrol’s use of the pipeline itself. Starting in February 2012, we are operating under a new transportation contract with Ecopetrol which changes the point at which Ecopetrol takes delivery of our oil. Previously, Ecopetrol took delivery of our oil at the beginning of the export pipeline. Under the new transportation contract, Ecopetrol takes delivery at the end of the export pipeline. This creates a risk of loss of oil due to sabotage by guerrillas or theft from the pipeline which may result in reduced revenues and increased clean-up or third party costs. We have attempted to mitigate the risk of increased costs with insurance and are investigating potential ways to mitigate the reduced revenue risk. Ecopetrol maintains responsibility for clean-up of any spilled oil and for pipeline repair.

Problems with these pipelines can cause interruptions to our producing activities if they are for a long enough duration that our storage facilities become full. For example, we experienced disruptions in transportation on this pipeline in March and April of 2008, June, July and August of 2009, June, August, and September 2010, February 2011, February to August of 2012 and October 2012 as a result of sabotage by guerrillas. In addition, there is competition for space in these pipelines, and additional discoveries in our area of operations by other companies could decrease the pipeline capacity available to us. Trucking is an alternative to transportation by pipeline; however, it is generally more expensive and carries higher safety risks for us, our employees and the public.

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

In addition, alternative transportation arrangements do not currently have capacity in order for us to deliver our regular volumes of sales. When disruptions are of a long enough duration, our sales volumes will be lower than normal, which will cause our cash flow to be lower than normal, and if our storage facilities become full, we can be forced to interrupt production.

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

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

The entire Argentine domestic refining market is small and export opportunities are limited by available infrastructure. As a result, our oil and gas sales in Argentina will depend on a relatively small group of customers, and currently, on two significant customers. The lack of competition in

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

In Brazil, there are a number of potential customers for our oil, and we are working to establish relationships with as many as possible to ensure a stable market for our oil. Currently, essentially all of our production in Brazil is sold to Petróleo Brasileiro S.A (“Petrobras”). Petrobras’ refinery in the area of our operations has had some technical difficulties which have restricted its ability to receive deliveries. Our second option in the area is at full capacity. This could mean that we cannot produce to full capacity in the area because of restrictions in being able to deliver our oil.

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

We operate our business in Colombia, Argentina, Peru, and Brazil, and may eventually expand to other countries. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, social unrest, strikes by local or national labor groups, interference with private contract rights (such as privatization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. For example, starting on November 21, 2008, we were forced to reduce production in Colombia on a gradual basis, culminating on December 11, 2008 when we suspended all production from the Santana, Guayuyaco and Chaza blocks in the Putumayo Basin. This temporary suspension of production operations was the result of a declaration of a state of emergency and force majeure by Ecopetrol due to a general strike in the region. In January 2009, the situation was resolved and we were able to resume production and sales shipments. Starting in 2010, there was an increased presence of illegitimate unionization activities in the Putumayo Basin by the Sindicato de Trabajadores Petroleros del Putumayo, which disrupted our operations from time to time and may do so in the future. During 2012 and 2011, Argentina has experienced increased union activity and this may create disruptions in our Argentine operations in the future. During 2012, we have also experienced related issues with landowners blocking access to our fields for short periods of time in Argentina. South America has a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. Any changes in oil and gas or investment regulations and policies or a shift in political attitudes in Argentina, Colombia, Peru or Brazil or other countries in which we intend to operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

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

In July 2012, the Argentine government mandated the creation of an oil planning commission that will set national energy goals and have the power to review private oil companies' investment plans. The committee will have the power to approve or reject annual investment plans that must be submitted by private companies by September 30 of each year. This decree is new and many details are yet to be announced. However, we believe there is a risk that this may cause delays in our operations in Argentina, or cause changes to our investment plans that could negatively effect our business in Argentina or the rest of our operations.

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

Our capital program for 2012 calls for approximately $380 million to fund our exploration and development, which we intend to fund through existing cash and cash flows from operations. Funding this program relies in part on oil prices remaining high and other factors to generate

sufficient cash flow. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our business plan which would cause us to decrease our exploration and development, which could harm our business outlook, investor confidence and our share price.

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

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

To develop our business, we endeavor to use the business relationships of our management and board of directors to enter into strategic and business relationships, which may take the form of joint ventures with other parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We also have an active business development program to develop those relationships and foster new relationships. We may not be able to establish these business relationships, or if established, we may choose the wrong partner or we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to take to fulfill our obligations to these partners or maintain our relationships. If we fail to make the cash calls required by our joint venture partners in the joint ventures we do not operate, we may be required to forfeit our interests in these joint ventures. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

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

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

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

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

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

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

The ANH has requested that the additional compensation be paid with respect to production from the recently drilled wells relating to the Moqueta discovery and has initiated a noncompliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, we view the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is our view that it is clear that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with

respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. Discussions with the ANH have not resolved this issue and we have sent notice to the ANH to initiate the dispute resolution process prescribed by the Chaza Contract. No assurance can be made that our interpretation will prevail and, depending on the ultimate size of the cumulative production from the Moqueta field in the future, such amounts may be material if such additional compensation must be paid. As at September 30, 2012, total cumulative production from the Moqueta field was 0.7 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $13.1 million. At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

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

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

The 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 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 oil and natural gas exports.

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

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

Currently most oil and gas producers in Argentina are operating without sales contracts. In 2008, a new withholding tax regime for exports was introduced without specific guidance as to its application. The domestic price was regulated in a similar way, so that both exported and domestically sold products were priced the same. Producers and refiners of oil in Argentina were unable to determine an agreed sales price for oil deliveries to refineries. In our case, the refineries’ price offered to oil producers reflects their price received, less taxes and operating costs and their usual mark up. Along with most other oil producers in Argentina, we are continuing negotiating sales on a spot price basis with refiners and the price is negotiated on a month by month basis. The Provincial governments have also been hurt by these changes as their effective royalty take has been reduced and capital investment in oilfields has declined, and so they are lobbying to change the situation. The government introduced the Petro Plus and Gas Plus programs in 2009, which grant higher prices to producers that sell production from new reserves. This is a positive step forward that will hopefully lead to further opening of price regulation in Argentina.

Recently, the government of Argentina has been active in the oil and gas business. On April 16, 2012, the government announced their intention to acquire a 51% interest in YPF from Repsol S.A. (Respol S.A. holds 56.7% of YPF), and retain 51% control for the Federal Government and distribute 49% of the shares to Argentine provinces. Prior to this announcement, various provincial governments announced contract cancellations effecting YPF, Petrobras Argentina S.A., and Azabache Energy Inc., among others. The reason cited for the contract cancellations was lack of activity in the areas in question. We have experienced recent success in Argentina and have active programs in all areas, which we believe helps mitigate our risk. However, despite the fact that our operating entity in Argentina is a locally incorporated company the employees of which are all Argentine, we are viewed as a foreign company and could therefore face increased risk.

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

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our executive team and other personnel in conducting our business. The loss of any of these individuals or our inability to attract suitably qualified individuals to replace any of them could materially adversely impact our business. We are experiencing difficulties in finding and retaining suitably qualified staff in certain jurisdictions, particularly in Brazil and Peru , where experienced personnel in our industry are in high demand and competition for their talents is intense.

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

*Foreign Currency Exchange Rate Fluctuations May Affect Our Financial Results.

We expect to sell our oil and natural gas production under agreements that will be denominated in United States dollars and foreign currencies. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. Our production in Argentina is primarily invoiced in United States dollars, but payment is made in Argentine pesos, at the then current exchange rate. As a result, we are exposed to translation risk when local currency financial statements are translated to United States dollars, our functional currency. Since September 1, 2005, exchange rates between the Colombian peso and U.S. dollar have varied between 1,648 pesos to one U.S. dollar to 2,632 pesos to one U.S. dollar, a fluctuation of approximately 60%. Since we began operating in Argentina (September 1, 2005), the rate of exchange between the Argentine peso and U.S. dollar has varied between 3.05 pesos to one U.S. dollar to 4.53 pesos to the U.S. dollar, a fluctuation of approximately 43%. Production in Brazil is invoiced and paid in Brazilian Reals. Since September 1, 2005, the exchange rate of the Brazilian Real has varied between 1.56 Reals to one U.S. dollar to 2.45 Reals to the U.S. dollar, a variance of 57%. Current and deferred tax liabilities in Colombia are denominated in Colombian pesos and the strengthening of 7.3% in the Colombian Peso against the U.S. dollar in the nine months ended September 30, 2012, resulted in a foreign exchange loss.

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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


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


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


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

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with ANH and Ecopetrol and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets.

Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. The United States may impose sanctions on Colombia in the future, and we cannot predict the effect in Colombia that these sanctions might cause.

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

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

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

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

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

Our strategy envisions continually expanding our business, both organically and through acquisition of other properties and companies. If we fail to effectively manage our growth or integrate successfully our acquisitions, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. Integration efforts place a significant burden on our management and internal resources. The diversion of management attention and any difficulties encountered in the integration process could harm our business, financial condition and results of operations. In addition, we must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new or acquired employees. We may not be able to:


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


•	allocate our human resources optimally;


•	identify and hire qualified employees or retain valued employees; or


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

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

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

The Shining Path Guerilla group has been active in Peru since the early 1980’s and, at one point, was active throughout the country. Recently, the group’s activity has been confined to small areas of Peru and operations have been hampered by the capture of many high profile leaders and membership has fallen dramatically. During April 2012, 30 people working on the Camisea natural gas project in central Peru were kidnapped. Most of the workers were released after a short period of time, and the remainder were freed within a few days. The kidnapping was attributed to the Shining Path Guerilla group. Camisea is a very large, high profile project in an area where the group continues to be active. Our operations in Peru are in a different region, with no known activity by the group. Nevertheless, we are concerned about the security of our operations in Peru and mitigate our risks through good relationships with local communities and stakeholders as well as strong security procedures.

Risks Related to Our Industry

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

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

To the extent that we succeed in discovering oil and/or natural gas, reserves may not be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and gas reserves. Without the addition of reserves through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets. Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and technical conditions. While we will endeavor to effectively manage these conditions, we may not be able to do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

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

We are subject to licensing and permitting requirements relating to exploring and drilling for and development of oil and natural gas, including seismic, environmental and many other operating permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. For example, the permitting process in Peru takes significant time, meaning that exploration and development projects have a longer cycle time to completion than they might elsewhere. Other drilling projects are being delayed because the Ministry of the Environment has not increased staffing levels to meet increased activity in the oil and gas industry in Colombia and so permit processing is taking longer than usual. These delays are also significantly impacting other industry participants. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations. For example, currently in Brazil, we are subject to restrictions on flaring natural gas, which have the impact of limiting our production capacity.

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

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

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

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

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

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

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

In 2011, we recorded a ceiling test impairment loss of $42.0 million in our Peru cost center related to seismic and drilling costs on two blocks which were relinquished and a ceiling test impairment loss of $25.7 million in our Argentina cost center related to an increase in estimated future operating and capital costs to produce our remaining Argentine proved reserves and a decrease in reserve volumes. In the nine months ended September 30, 2012, we recorded a ceiling test impairment loss of $20.2 million in our Brazil cost center related to seismic and drilling costs on Block BM-CAL-10. The farmout agreement for that block terminated during the first quarter of 2012 when we provided notice that we would not enter into the second exploration period.

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

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. Earthquakes or weather related phenomena such as heavy rain, landslides, storms and hurricanes can also cause problems in drilling new wells. There are also risks in producing oil and natural gas from existing facilities. For example, the Valle Morado GTE.St.VMor-2001 re-entry operations started in the third quarter of 2010, with integrity testing and remediation operations required for the sidetrack operations. Due to operational difficulties, the initial side-track attempt was not successful. The operation was placed on standby pending the arrival of additional side-track equipment and operations recommenced in the fourth quarter of 2010. In February 2011, these operations were suspended and the wellbore has been abandoned due to a number of operational challenges encountered. We continue to review alternatives associated with the field development. Also for example, on February 7, 2009 we experienced an incident at our Juanambu-1 well, involving a fire in a generator, resulting in total damage to equipment estimated at $500,000, and production in the amount of approximately $125,000 being deferred due to shutting down production facilities while dealing with the incident. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. Incidents such as these can lead to serious injury, property damage and even loss of life. We generally obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

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

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

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

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

*Prices and Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate Significantly, Which Could Reduce Our Profitability, Growth and Value.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for WTI per barrel was $66 in 2006, $72 in 2007, $100 in 2008, $62 in 2009, $79 in 2010, $95 in 2011 and $96 for the nine months ending September 30, 2012, demonstrating the inherent volatility in the market. Average Brent oil prices for the three and nine months ended September 30, 2012, were $109.61 and $112.20 per bbl. Given the current economic environment and unstable conditions in the Middle East, North Africa, the United States and Europe, the oil price environment is increasingly unpredictable and unstable. We expect that prices will fluctuate in the future. Price fluctuations will have a significant

impact upon our revenue, the return from our oil and gas reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differentials. These differentials can change over time and have a detrimental impact on realized prices. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

In addition, oil and natural gas prices in Argentina are effectively regulated and during 2009, 2010, 2011 and 2012, were substantially lower than those received in North America. Oil prices in Colombia are related to international market prices, but adjustments that are defined by contract with Ecopetrol, the purchaser of most of the oil that we produce in Colombia, may cause realized prices to be lower or higher than those received in North America. Oil prices in Brazil are defined by contract with the refinery and may be lower or higher than those received in North America.

Penalties We May Incur Could Impair Our Business.

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

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

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

Environmental Risks May Adversely Affect Our Business.

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

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

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

Challenges to Our Properties May Impact Our Financial Condition.

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

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

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

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

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

Risks Related to Our Common Stock

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

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


•	dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with acquisitions of other companies or assets;


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


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


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


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


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


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


•	changes in analysts’ estimates affecting us, our competitors and/or our industry;


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


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


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


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


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

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


•	quarterly variations in our revenues and operating expenses; and


•	additions and departures of key personnel.

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

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

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

Item 6. Exhibits

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

SIGNATURES

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

GRAN TIERRA ENERGY INC.



Date: November 7, 2012	/s/ Dana Coffield
	By: Dana Coffield
	Chief Executive Officer and President
	(Principal Executive Officer)



Date: November 7, 2012	/s/ James Rozon
	By: James Rozon Chief Financial Officer
	(Principal Financial and Accounting Officer)

EXHIBIT INDEX



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

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

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

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

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

4.1	Reference is made to Exhibits 3.1 to 3.2.

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

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

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

10.1	Addendum No. 2 to the Purchase Agreement between Gran Tierra Energy Colombia Ltd. and Ecopetrol S.A. with respect to the sale of crude oil from the Chaza Block, Santana Block and Guayuyaco Block.	Filed herewith.

10.2	Addendum No. 2 to the Purchase Agreement between Solana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A. with respect to the sale of crude oil from the Chaza Block, Santana Block and Guayuyaco Block.	Filed herewith.

10.3	Addendum No. 1 to the Transportation Agreement between Gran Tierra Energy Colombia Ltd. and Ecopetrol S.A.	Filed herewith.

10.4	Addendum No. 1 to the Transportation Agreement between Solana Petroleum Exploration Colombia Ltd. and Ecopetrol S.A.	Filed herewith.

10.5	Sixth Amendment to Credit Agreement, dated as of October 9, 2012, among Solana Resources Limited, Gran Tierra Energy Inc., Wells Fargo Bank, National Association, and the Lenders	Filed herewith.

31.1	Certification of Principal Executive Officer	Filed herewith.

31.2	Certification of Principal Financial Officer	Filed herewith.

32.1	Section 1350 Certifications.	Filed herewith.

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema Document

101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB* XBRL Taxonomy Extension Label Linkbase Document

101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

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

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